[Federal Register Volume 77, Number 140 (Friday, July 20, 2012)]
[Proposed Rules]
[Pages 42834-42871]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-17659]



[[Page 42833]]

Vol. 77

Friday,

No. 140

July 20, 2012

Part II





Environmental Protection Agency





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40 CFR Part 51





 Approval, Disapproval and Promulgation of Air Quality Implementation 
Plans; Arizona; Regional Haze State and Federal Implementation Plans; 
Proposed Rule

  Federal Register / Vol. 77 , No. 140 / Friday, July 20, 2012 / 
Proposed Rules  

[[Page 42834]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 51

[EPA-R09-OAR-2012-0021, FRL-9700-1]


Approval, Disapproval and Promulgation of Air Quality 
Implementation Plans; Arizona; Regional Haze State and Federal 
Implementation Plans

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to approve partially and disapprove partially 
a revision to Arizona's State Implementation Plan (SIP) to implement 
the regional haze program for the first planning period through July 
31, 2018. This proposed action addresses only the portion of the SIP 
related to Arizona's determination of Best Available Retrofit 
Technology (BART) to control emissions from eight units at three 
electric generating stations: Apache Generating Station, Cholla Power 
Plant and Coronado Generating Station. EPA proposes to approve the 
State's determination that these sources are subject to BART, and to 
approve the emissions limits for sulfur dioxide (SO2) and 
particulate matter (PM10) at all the units. EPA proposes to 
disapprove the BART emissions limits for nitrogen oxides 
(NOX) at most of the units. EPA also proposes to promulgate 
a Federal Implementation Plan (FIP) containing new emissions limits for 
NOX as well as BART compliance requirements for the three 
facilities. We encourage the State to submit a revised SIP to replace 
all portions of our FIP, and we stand ready to work with the State to 
develop a revised plan. The Clean Air Act (CAA) requires states to 
prevent any future and remedy any existing man-made impairment of 
visibility in 156 national parks and wilderness areas designated as 
Class I areas. Arizona has a wealth of such areas. The three power 
plants affect visibility at 18 national parks and wilderness areas, 
including the Grand Canyon, Mesa Verde and the Petrified Forest. The 
State and EPA must work together to ensure that plans are in place to 
make progress toward natural visibility conditions at these national 
treasures.

DATES: Written comments must be received by the designated contact at 
the address below on or before August 31, 2012.

ADDRESSES: See the SUPPLEMENTARY INFORMATION section for further 
instructions on where and how to learn more about this proposal, attend 
a public hearing, or submit comments.

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9, 
Planning Office, Air Division, Air-2, 75 Hawthorne Street, San 
Francisco, CA 94105. Thomas Webb can be reached at telephone number 
(415) 947-4139 and via electronic mail at [email protected].

SUPPLEMENTARY INFORMATION:

Table of Contents

I. General Information
    A. Definitions
    B. Docket
    C. Instructions for Submitting Comments to EPA
    D. Submitting Confidential Business Information
    E. Tips for Preparing Your Comments
    F. Public Hearings
II. Overview of Proposed Actions
III. Regional Haze Background
    A. Description of Regional Haze
    B. History of Regional Haze Regulations
    C. Roles of Agencies in Addressing Regional Haze
IV. Requirements for Regional Haze Implementation Plans
    A. Regional Haze Rule
    B. The Deciview
    C. Best Available Retrofit Technology
    D. The Grand Canyon Visibility Transport Commission and Section 
309
V. SIP and FIP Background
    A. History of State Submittals and EPA Actions
    B. EPA's Authority To Promulgate a FIP
VI. EPA's Evaluation of Arizona's BART Analyses and Determinations
    A. Arizona's Identification of BART Sources
    B. Arizona's BART Control Analysis
    1. Cost of Compliance
    2. Energy and Non-Air Quality Environmental Impacts
    3. Existing Pollution Control Technology
    4. Remaining Useful Life of the Source
    5. Degree of Visibility Improvement
    C. Arizona's BART Determinations
    1. Apache Unit 1
    a. BART for NOX
    b. BART for PM10
    c. BART for SO2
    2. Apache Units 2 and 3
    a. BART for NOX
    b. BART for PM10
    c. BART for SO2
    3. Cholla Units 2, 3 and 4
    a. BART for NOX
    b. BART for PM10
    c. BART for SO2
    4. Coronado Units 1 and 2
    a. BART for NOX
    b. BART for PM10
    c. BART for SO2
    D. Enforceability of BART Limits
VII. EPA's Proposed FIP Actions
    A. EPA's BART Analyses and Determinations
    1. Costs of Compliance
    2. Energy and Non-Air Environmental Impacts
    3. Pollution Control Equipment in Use at the Source
    4. Remaining Useful Life of the Source
    5. Degree of Improvement in Visibility
    a. Modeling Protocol
    b. Baseline Emissions
    c. Emission Reductions for Alternative Controls
    d. Visibility Impacts
    B. EPA's FIP BART Determinations
    1. Apache Units 2 and 3
    a. Costs of Compliance
    b. Visibility Improvement
    c. EPA's BART Determinations
    2. Cholla Units 2, 3 and 4
    a. Costs of Compliance
    b. Visibility Improvement
    c. EPA's BART Determinations
    3. Coronado Units 1 and 2
    a. Costs of Compliance
    b. Visibility Improvement
    c. EPA's BART Determinations
    C. Enforceability Requirements
VIII. Summary of EPA's Proposed Action
IX. Statutory and Executive Order Reviews

I. General Information

 A. Definitions

    For the purpose of this document, we are giving meaning to certain 
words or initials as follows:
    (1) The words or initials Act or CAA mean or refer to the Clean Air 
Act, unless the context indicates otherwise.
    (2) The initials ADEQ mean or refer to the Arizona Department of 
Environmental Quality.
    (3) The initials AEPCO mean or refer to Arizona Electric Power 
Cooperative.
    (4) The initials AFUDC mean or refer to allowance for funds used 
during construction.
    (5) The initials APS mean or refer Arizona Public Service Company.
    (6) The words Arizona and State mean the State of Arizona.
    (7) The initials BART mean or refer to Best Available Retrofit 
Technology.
    (8) The term Class I area refers to a mandatory Class I Federal 
area.\1\
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    \1\ Although states and tribes may designate as Class I 
additional areas which they consider to have visibility as an 
important value, the requirements of the visibility program set 
forth in section 169A of the CAA apply only to ``mandatory Class I 
Federal areas.''
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    (9) The initials CBI mean or refer to Confidential Business 
Information.
    (10) The initials CEMS mean or refer to continuous emission 
monitoring system.
    (11) The initials COFA mean or refer to close-coupled overfire air.
    (12) The initials CY mean or refer to Calendar Year
    (13) The initials EGU mean or refer to Electric Generating Unit.
    (14) The initials ESPs mean or refer to electrostatic 
precipitators.
    (15) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.

[[Page 42835]]

    (16) The initials FGD mean or refer to flue gas desulfurization.
    (17) The initials FGR mean or refer to flue gas recirculation.
    (18) The initials FIP mean or refer to Federal Implementation Plan.
    (19) The initials FLMs mean or refer to Federal Land Managers.
    (20) The initials IMPROVE mean or refer to Interagency Monitoring 
of Protected Visual Environments monitoring network.
    (21) The initials IPM mean or refer to Integrated Planning Model.
    (22) The initials LNB mean or refer to low-NOX burners.
    (23) The initials LTS mean or refer to Long-Term Strategy.
    (24) The initials MW mean or refer to megawatts.
    (25) The initials NEI mean or refer to National Emission Inventory.
    (26) The initials NH3 mean or refer to ammonia.
    (27) The initials NOX mean or refer to nitrogen oxides.
    (28) The initials NP mean or refer to National Park.
    (29) The initials OC mean or refer to organic carbon.
    (30) The initials OFA mean or refer to over fire air.
    (31) The initials PM mean or refer to particulate matter.
    (32) The initials PM2.5 mean or refer to fine particulate matter 
with an aerodynamic diameter of less than 2.5 micrometers.
    (33) The initials PM10 mean or refer to particulate matter with an 
aerodynamic diameter of less than 10 micrometers (coarse particulate 
matter).
    (34) The initials PNG mean or refer to pipeline natural gas.
    (35) The initials ppm mean or refer to parts per million.
    (36) The initials PSD mean or refer to Prevention of Significant 
Deterioration.
    (37) The initials RAVI mean or refer to Reasonably Attributable 
Visibility Impairment.
    (38) The initials RMC mean or refer to Regional Modeling Center.
    (39) The initials RP mean or refer to Reasonable Progress.
    (40) The initials RPG or RPGs mean or refer to Reasonable Progress 
Goal(s).
    (41) The initials RPOs mean or refer to regional planning 
organizations.
    (42) The initials SCR mean or refer to Selective Catalytic 
Reduction.
    (43) The initials SIP mean or refer to State Implementation Plan.
    (44) The initials SNCR mean or refer to Selective Non-catalytic 
Reduction.
    (45) The initials SO2 mean or refer to sulfur dioxide.
    (46) The initials SOFA mean or refer to separated over fire air.
    (47) The initials SRP mean or refer to Salt River Project 
Agricultural Improvement and Power District.
    (48) The initials tpy mean tons per year.
    (49) The initials TSD mean or refer to Technical Support Document.
    (50) The initials VOC mean or refer to volatile organic compounds.
    (51) The initials WA mean or refer to Wilderness Area.
    (52) The initials WEP mean or refer to Weighted Emissions 
Potential.
    (53) The initials WFGD mean or refer to wet flue gas 
desulfurization.
    (54) The initials WRAP mean or refer to the Western Regional Air 
Partnership.

B. Docket

    The proposed action relies on documents, information and data that 
are listed in the index on http://www.regulations.gov under docket 
number EPA-R09-OAR-2012-0021. Although listed in the index, some 
information is not publicly available (e.g., Confidential Business 
Information (CBI)). Certain other material, such as copyrighted 
material, is publicly available only in hard copy form. Publicly 
available docket materials are available either electronically at 
http://www.regulations.gov or in hard copy at the Planning Office of 
the Air Division, AIR-2, EPA Region 9, 75 Hawthorne Street, San 
Francisco, CA 94105. EPA requests that you contact the individual 
listed in the FOR FURTHER INFORMATION CONTACT section to view the hard 
copy of the docket. You may view the hard copy of the docket Monday 
through Friday, 9-5:00 PDT, excluding Federal holidays.

 C. Instructions for Submitting Comments to EPA

    Written comments must be received at the address below on or before 
August 31, 2012. Submit your comments, identified by Docket ID No. EPA-
R09-OAR-2011-0021, by one of the following methods:
     Federal Rulemaking portal: http://www.regulations.gov. 
Follow the on-line instructions for submitting comments.
     Email: [email protected].
     Fax: 415-947-3579 (Attention: Thomas Webb).
     Mail, Hand Delivery or Courier: Thomas Webb, EPA Region 9, 
Air Division (AIR-2), 75 Hawthorne Street, San Francisco, California 
94105. Hand and courier deliveries are only accepted Monday through 
Friday, 8:30 a.m.-4:30 p.m., excluding Federal holidays. Special 
arrangements should be made for deliveries of boxed information.
    EPA's policy is to include all comments received in the public 
docket without change. We may make comments available online at http://www.regulations.gov, including any personal information provided, 
unless the comment includes information claimed to be CBI or other 
information for which disclosure is restricted by statute. Do not 
submit information that you consider to be CBI or that is otherwise 
protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site is an ``anonymous access'' system, which 
means EPA will not know your identity or contact information unless you 
provide it in the body of your comment. If you send an email comment 
directly to EPA, without going through http://www.regulations.gov, we 
will include your email address as part of the comment that is placed 
in the public docket and made available on the Internet. If you submit 
an electronic comment, EPA recommends that you include your name and 
other contact information in the body of your comment and with any disk 
or CD-ROM you submit. If EPA cannot read your comment due to technical 
difficulties and cannot contact you for clarification, EPA may not be 
able to consider your comment. Electronic files should not include 
special characters or any form of encryption, and be free of any 
defects or viruses.

D. Submitting Confidential Business Information

    Do not submit CBI to EPA through http://www.regulations.gov or 
email. Clearly mark the part or all of the information that you claim 
as CBI. For CBI information in a disk or CD-ROM that you mail to EPA, 
mark the outside of the disk or CD-ROM as CBI and identify 
electronically within the disk or CD-ROM the specific information that 
is claimed as CBI. In addition to one complete version of the comment 
that includes information claimed as CBI, you must submit a copy of the 
comment that does not contain the information claimed as CBI for 
inclusion in the public docket. We will not disclose information so 
marked except in accordance with procedures set forth in 40 CFR part 2.

E. Tips for Preparing Your Comments

    When submitting comments, remember to:
     Identify the rulemaking by docket number and other 
identifying information (e.g., subject heading, Federal Register date 
and page number).
     Explain why you agree or disagree; suggest alternatives 
and substitute language for your requested changes.

[[Page 42836]]

     Describe any assumptions and provide any technical 
information and/or data that you used.
     If you estimate potential costs or burdens, explain how 
you arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
     Provide specific examples to illustrate your concerns, and 
suggest alternatives.
     Explain your views as clearly as possible, avoiding the 
use of profanity or personal threats.
     Make sure to submit your comments by the identified 
comment period deadline.

F. Public Hearings

    EPA will hold a public hearing at the date, time and location 
stated below to accept oral and written comments into the record.
    Date: July 31, 2012.
    Open House: 4:00-5:00 p.m.
    Public Hearing: 6:00-8:00 p.m.
    Location: Sandra Day O'Connor Federal Courthouse (atrium and juror 
room), 401 W. Washington Street, Phoenix, AZ 85003-2118.
    To provide opportunities for questions and discussion, EPA will 
hold an open house prior to the public hearing. During the open house, 
EPA staff will be available informally to answer questions on our 
proposed rule. Any comments made to EPA staff during the open house 
must still be provided formally in writing or orally during a public 
hearing in order to be considered in the record.
    The public hearing will provide the public with an opportunity to 
present views or information concerning the proposed Regional Haze FIP 
for Arizona. EPA may ask clarifying questions during the oral 
presentations, but will not respond to the presentations at that time. 
Simultaneous translation in Spanish will be available during the public 
hearing. We will consider written statements and supporting information 
submitted during the comment period with the same weight as any oral 
comments and supporting information presented at the public hearing. 
Please consult section I.C, I.D. and I.E of this preamble for guidance 
on how to submit written comments to EPA. We will include verbatim 
transcripts of the hearing in the docket for this action. The EPA 
Region 9 Web site for the rulemaking, which includes the proposal and 
information about the public hearing, is at http://www.epa.gov/region9/air/actions.

II. Overview of Proposed Actions

    EPA proposes to partially approve and partially disapprove a 
portion of Arizona's SIP for Regional Haze submitted to EPA Region 9 on 
February 28, 2011, to meet the requirements of Section 308 of the 
Regional Haze Rule. EPA is proposing to take action only on the BART 
requirements for the three electric generating stations and units 
listed in Table 1. At this time, EPA is not proposing to take action on 
the State's other BART determinations or any other parts of the SIP 
regarding the remaining requirements of the Regional Haze Rule. EPA 
takes very seriously a decision to disapprove a state plan, as we 
believe that it is preferable, and preferred in the provisions of the 
Clean Air Act, that these requirements be implemented through state 
plans. A state plan need not contain exactly the same provisions that 
EPA might require, but EPA must be able to find that the state plan is 
consistent with the requirements of the Act. Further, EPA's oversight 
role requires that it assure fair implementation of Clean Air Act 
requirements by states across the country, even while acknowledging 
that individual decisions from source to source or state to state may 
not have identical outcomes. In this instance, we believe that 
Arizona's SIP generally meets those requirements with respect to its 
SO2 and PM10 limits, but as we describe in more 
detail below, the SIP does not include several specifically required 
elements. The NOX BART determinations for the coal-fired 
units are neither consistent with the requirements of the Act nor with 
BART decisions that other states have made. As a result, EPA believes 
this proposed disapproval is the only path that is consistent with the 
Act at this time. Specifically, we propose the following:
     Proposed Approval: EPA proposes to approve Arizona's 
determination that the following sources and units are subject to BART: 
Arizona Electric Power Company's (AEPCO) Apache Generating Station 
(Apache) Units 1, 2 and 3; Arizona Public Service's (APS) Cholla Power 
Plant (Cholla) Units 2, 3 and 4; and Salt River Project's (SRP) 
Coronado Generating Station (Coronado) Units 1 and 2. We are proposing 
to approve the State's emissions limits for SO2 and 
PM10 at all of these units, but are seeking comment on 
whether lower emissions limits may be warranted for any of these units, 
and whether an alternative test method should be accepted for 
measurement of PM10. Finally, we are proposing to approve 
the emissions limits for NOX, SO2 and 
PM10 at Apache Unit 1.
     Proposed Disapproval: Based on our evaluation described in 
this notice, we propose to disapprove the State's BART emissions limits 
for NOX at all three sources and units except for Coronado 
Unit 2 and Apache Unit 1. We also propose to disapprove the compliance 
and equipment maintenance requirements for BART at all three sources, 
since these were not included in the revised SIP.\2\
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    \2\ For each BART source, the SIP must include a requirement to 
install and operate control equipment as expeditiously as 
practicable (40 CFR 51.308(e)(1)(iv)); a requirement to maintain 
control equipment (40 CFR 51.308(e)(1)(v)); and procedures to ensure 
control equipment is properly operated and maintained, including 
requirements for monitoring, recordkeeping and reporting (40 CFR 
51.308(e)(1)(v)).
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     Proposed FIP: We propose to promulgate a Federal 
Implementation Plan (FIP) that includes emissions limitations 
representing BART for NOX at all units except for Apache 
Unit 1. The proposed FIP also includes compliance schedules and 
requirements for equipment maintenance, monitoring, testing, 
recordkeeping and reporting for all the sources and units. The 
regulatory language for the FIP requirements is listed under PART 52 at 
the end of this notice.

                                        Table 1--Scope of Proposed Action
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            Source name                       Owner                   Units                   Pollutants
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Apache Generating Station..........  AEPCO.................  Steam Units 1, 2 and 3  NOX, SO2, PM10
Cholla Power Plant.................  APS...................  Steam Units 2, 3 and 4  NOX, SO2, PM10
Coronado Generating Station........  SRP...................  Units 1 and 2.........  NOX, SO2, PM10
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[[Page 42837]]

III. Regional Haze Background

A. Description of Regional Haze

    Regional haze is visibility impairment that is produced by a 
multitude of sources and activities that are located across a broad 
geographic area and emit fine particulates (e.g., sulfates, nitrates, 
organic carbon (OC), elemental carbon (EC), and soil dust), and their 
precursors (e.g., sulfur dioxide, nitrogen oxides, and in some cases, 
ammonia (NH3) and volatile organic compounds (VOC)). Fine 
particle precursors react in the atmosphere to form PM2.5, 
which impairs visibility by scattering and absorbing light. Visibility 
impairment reduces the clarity, color, and visible distance that one 
can see. PM2.5 can also cause serious health effects and 
mortality in humans and contributes to environmental effects such as 
acid deposition and eutrophication.
    Data from the existing visibility monitoring network, the 
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE) 
monitoring network, show that visibility impairment caused by air 
pollution occurs virtually all the time at most national parks (NPs) 
and wilderness areas (WAs). The average visual range \3\ in many Class 
I areas (i.e., NPs and memorial parks, WAs, and international parks 
meeting certain size criteria) in the western United States is 100-150 
kilometers, or about one-half to two-thirds of the visual range that 
would exist without anthropogenic air pollution. In most of the eastern 
Class I areas of the United States, the average visual range is less 
than 30 kilometers, or about one-fifth of the visual range that would 
exist under estimated natural conditions (64 FR 35715, July 1, 1999).
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    \3\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
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B. History of Regional Haze Regulations

    In section 169A of the 1977 Amendments to the CAA, Congress created 
a program for protecting visibility in the nation's national parks and 
wilderness areas. This section of the CAA establishes as a national 
goal the ``prevention of any future, and the remedying of any existing, 
impairment of visibility in mandatory Class I Federal areas \4\ which 
impairment results from manmade air pollution.'' EPA promulgated 
regulations on December 2, 1980, to address visibility impairment in 
Class I areas that is ``reasonably attributable'' to a single source or 
small group of sources, i.e., ``reasonably attributable visibility 
impairment.'' (45 FR 80084, December 2, 1980). These regulations 
represented the first phase in addressing visibility impairment. EPA 
deferred action on regional haze that emanates from a variety of 
sources until monitoring, modeling and scientific knowledge about the 
relationships between pollutants and visibility impairment were 
improved.
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    \4\ Areas designated as mandatory Class I Federal areas consist 
of national parks exceeding 6000 acres, wilderness areas and 
national memorial parks exceeding 5000 acres, and all international 
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a). 
In accordance with section 169A of the CAA, EPA, in consultation 
with the Department of Interior, promulgated a list of 156 areas 
where visibility is identified as an important value (44 FR 69122, 
November 30, 1979). The extent of a mandatory Class I area includes 
subsequent changes in boundaries, such as park expansions. 42 U.S.C. 
7472(a). Although states and tribes may designate as Class I 
additional areas which they consider to have visibility as an 
important value, the requirements of the visibility program set 
forth in section 169A of the CAA apply only to ``mandatory Class I 
Federal areas.'' Each mandatory Class I Federal area is the 
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i). 
When we use the term ``Class I area'' in this action, we mean a 
``mandatory Class I Federal area.''
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    As part of the 1990 Amendments to the CAA, Congress added section 
169B to focus attention on regional haze issues. EPA promulgated a rule 
to address regional haze on July 1, 1999 (64 FR 35714, July 1, 1999) 
codified at 40 CFR part 51, subpart P (Regional Haze Rule). The primary 
regulatory requirements that address regional haze are found at 40 CFR 
51.308 and 51.309 and are summarized below. Under 40 CFR 51.308(b), all 
states, the District of Columbia and the Virgin Islands are required to 
submit an initial state implementation plan (SIP) addressing regional 
haze visibility impairment no later than December 17, 2007.\5\
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    \5\ EPA's regional haze regulations require subsequent updates 
to the regional haze SIPs. 40 CFR 51.308(g)-(i).
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C. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the regional haze program will require 
long-term regional coordination among states, tribal governments and 
various federal agencies. As noted above, pollution affecting the air 
quality in Class I areas can be transported over long distances, even 
hundreds of kilometers. Therefore, to effectively address the problem 
of visibility impairment in Class I areas, states, or the EPA when 
implementing a FIP, need to develop strategies in coordination with one 
another, taking into account the effect of emissions from one 
jurisdiction on the air quality in another.
    Because the pollutants that lead to regional haze can originate 
from sources located across broad geographic areas, EPA has encouraged 
the states and tribes across the United States to address visibility 
impairment from a regional perspective. Five regional planning 
organizations (RPOs) were developed to address regional haze and 
related issues. The RPOs first evaluated technical information to 
better understand how their states and tribes impact Class I areas 
across the country, and then pursued the development of regional 
strategies to reduce emissions of particulate matter and other 
pollutants leading to regional haze.
    The Western Regional Air Partnership (WRAP) RPO is a collaborative 
effort of state governments, tribal governments, and various federal 
agencies established to initiate and coordinate activities associated 
with the management of regional haze, visibility and other air quality 
issues in the western United States. WRAP member State governments 
include: Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, 
New Mexico, North Dakota, Oregon, South Dakota, Utah, Washington, and 
Wyoming. Tribal members include Campo Band of Kumeyaay Indians, 
Confederated Salish and Kootenai Tribes, Cortina Indian Rancheria, Hopi 
Tribe, Hualapai Nation of the Grand Canyon, Native Village of Shungnak, 
Nez Perce Tribe, Northern Cheyenne Tribe, Pueblo of Acoma, Pueblo of 
San Felipe, and Shoshone-Bannock Tribes of Fort Hall.

IV. Requirements for Regional Haze Implementation Plans

A. Regional Haze Rule

    The Regional Haze Rule (RHR) sets out specific requirements for 
states' initial regional haze implementation plans.\6\ In particular, 
each state's plan must establish a long-term strategy that ensures 
reasonable progress toward achieving natural visibility conditions in 
each Class I area affected by the emissions from sources within the 
state. In addition, for each Class I area within the state's 
boundaries, the plan must establish a reasonable progress goal (RPG) 
for the first planning period that ends on July 31, 2018. The long-term 
strategy must include enforceable emission limits and other measures as 
necessary to achieve the RPG. Regional haze plans must also give 
specific

[[Page 42838]]

attention to certain stationary sources that were in existence on 
August 7, 1977, but were not in operation before August 7, 1962. These 
sources, where appropriate, are required to install BART controls to 
eliminate or reduce visibility impairment. Although such BART 
determinations can be a part of a reasonable progress strategy, BART is 
also an independent requirement that can be assessed separately from 
the other requirements of the RHR. Because this proposal only pertains 
to BART at three specific sources, we do not discuss other requirements 
of the RHR below.
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    \6\ Pursuant to 40 CFR 51.301, ``implementation plan'' is 
defined as ``any State Implementation Plan, Federal Implementation 
Plan, or Tribal Implementation Plan.'' Therefore, although the 
requirements of the RHR are generally described in relation to SIPs, 
they are also relevant where EPA is promulgating a regional haze 
plan.
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B. The Deciview

    The RHR establishes the deciview (dv) as the principal metric for 
measuring visibility. This visibility metric expresses uniform changes 
in haziness in terms of common increments across the entire range of 
visibility conditions, from pristine to extremely hazy conditions. 
Visibility expressed in deciviews is determined by using air quality 
measurements to estimate light extinction and then transforming the 
value of light extinction to deciviews using a logarithmic function. 
The deciview is a more useful measure for tracking progress in 
improving visibility than light extinction because each deciview change 
is an equal incremental change in visibility as perceived by the human 
eye.\7\
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    \7\ The preamble to the RHR provides additional details about 
the deciview (64 FR 35714, 35725 July 1, 1999).
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C. Best Available Retrofit Technology

    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often uncontrolled, older 
stationary sources in order to address visibility impacts from these 
sources. Specifically, section 169A(b)(2)(A) of the CAA requires states 
to revise their SIPs to contain such measures as may be necessary to 
make reasonable progress towards the natural visibility goal, including 
a requirement that certain categories of existing major stationary 
sources \8\ built between 1962 and 1977 procure, install, and operate 
the ``Best Available Retrofit Technology'' as determined by the state. 
Under the RHR, states are directed to conduct BART determinations for 
such ``BART-eligible'' sources that may be anticipated to cause or 
contribute to any visibility impairment in a Class I area. Rather than 
requiring source-specific BART controls, states also have the 
flexibility to adopt an emissions trading program or other alternative 
program as long as the alternative provides greater reasonable progress 
towards improving visibility than BART.
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    \8\ The set of ``major stationary sources'' potentially subject 
to BART is listed in CAA section 169A(g)(7).
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    EPA published the Guidelines for BART Determinations under the 
Regional Haze Rule at Appendix Y to 40 CFR part 51 (hereinafter 
referred to as the ``BART Guidelines'') on July 6, 2005. The Guidelines 
are to assist states in determining which of their sources should be 
subject to the BART requirements and in determining appropriate 
emission limits for each such ``subject-to-BART'' source. In making 
BART determinations for fossil fuel-fired electric generating plants 
with a total generating capacity in excess of 750 megawatts, states 
must use the approach set forth in the BART Guidelines. States are 
encouraged, but not required, to follow the BART Guidelines in making 
BART determinations for other types of sources. States must address all 
visibility-impairing pollutants emitted by a source in the BART 
determination process. The most significant visibility impairing 
pollutants are SO2, NOX and PM. EPA has indicated 
that states should use their best judgment in determining whether VOC 
or NH3 compounds impair visibility in Class I areas.
    Under the BART Guidelines, states may select an exemption threshold 
value for their BART modeling, below which a BART-eligible source would 
not be expected to cause or contribute to visibility impairment in any 
Class I area. The state must document this exemption threshold value in 
the SIP and must state the basis for its selection of that value. Any 
source with emissions that model above the threshold value would be 
subject to a BART determination review. The BART Guidelines acknowledge 
varying circumstances affecting different Class I areas. In setting 
their exemption threshold values, states should consider the number of 
emission sources affecting the Class I areas at issue and the magnitude 
of the individual sources' impacts. An exemption threshold set by the 
state should not be higher than 0.5 deciview.
    In their SIPs, states must identify potential BART sources, 
described in the RHR as ``BART-eligible sources,'' and document their 
BART control determination analyses. In making BART determinations, 
section 169A(g)(2) of the CAA requires that states consider the 
following factors: (1) The costs of compliance; (2) the energy and non-
air quality environmental impacts of compliance; (3) any existing 
pollution control technology in use at the source; (4) the remaining 
useful life of the source; and (5) the degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of such technology. States are free to determine the weight and 
significance assigned to each factor, but must consider all five 
factors and provide a reasoned explanation for adopting the technology 
selected as BART, based on the five factors.
    A regional haze SIP must include source-specific BART emission 
limits and compliance schedules for each source subject to BART, unless 
the SIP includes an alternative program that provides greater 
reasonable progress towards improving visibility than BART and meets 
the other requirements of 40 CFR 51.308(e)(2). Once a state has made 
its BART determination, the BART controls must be installed and in 
operation as expeditiously as practicable, but no later than five years 
after the date EPA approves the regional haze SIP.\9\ The Regional Haze 
SIP must also contain a requirement for each BART source to maintain 
the relevant control equipment, as well as procedures to ensure control 
equipment is properly operated and maintained.\10\ In addition to what 
is required by the RHR, general SIP requirements mandate that the SIP 
must also include all regulatory requirements related to monitoring, 
recordkeeping and reporting for the BART emissions limitations.\11\
---------------------------------------------------------------------------

    \9\ CAA section 169(g)(4); 40 CFR 51.308(e)(1)(iv).
    \10\ 40 CFR 51.308(e)(1)(v). See also CAA section 302(k) 
(defining ``emission limitation'' as ``a requirement established by 
the State or the Administrator which limits the quantity, rate, or 
concentration of emissions of air pollutants on a continuous basis, 
including any requirement relating to the operation or maintenance 
of a source to assure continuous emission reduction * * *'') 
(emphasis added).
    \11\ See CAA section 110(a)(2) (requirements for SIPs).
---------------------------------------------------------------------------

D. The Grand Canyon Visibility Transport Commission and Section 309

    In addition to the general requirements of the regional haze 
program, the RHR also includes 40 CFR 51.309, which contains the 
strategies developed by the Grand Canyon Visibility Transport 
Commission (GCVTC), established under Section 169B(f) of CAA, 42 U.S.C. 
7492(f). Certain western States and Tribes were eligible to submit 
implementation plans under section 309 as an alternative method of 
achieving reasonable progress for Class I areas that were covered by 
the GCVTC's analysis--i.e., the 16 Class I areas on the Colorado 
Plateau. In order for States and Tribes to be able to utilize this 
section, however, the rule provided that EPA must receive an ``Annex'' 
to

[[Page 42839]]

the GCVTC's final recommendations. The purpose of the Annex was to 
provide the specific provisions needed to translate the GCVTC's general 
recommendations for stationary source SO2 reductions into an 
enforceable regulatory program. The rule provided that such an Annex, 
meeting certain requirements, be submitted to EPA no later than October 
1, 2000, see 40 CFR 51.309(d)(4) and 51.309(f). The Annex was submitted 
in 2000, and EPA revised 40 CFR 51.309 in 2003. See 68 FR 33764, June 
5, 2003.

V. SIP and FIP Background

A. History of State Submittals and EPA Actions

    Since four of its twelve mandatory Class I Federal areas are on the 
Colorado Plateau, Arizona had the option of submitting a Regional Haze 
SIP under section 309 of the Regional Haze Rule. A SIP that is approved 
by EPA as meeting all of the requirements of section 309 is ``deemed to 
comply with the requirements for reasonable progress with respect to 
the 16 Class I areas [on the Colorado Plateau] for the period from 
approval of the plan through 2018.'' 40 CFR 51.309(a). When these 
regulations were first promulgated, 309 submissions were due no later 
than December 31, 2003. Accordingly, the Arizona Department of 
Environmental Quality (ADEQ) submitted to EPA on December 23, 2003, a 
309 SIP for Arizona's four Class I Areas on the Colorado Plateau. ADEQ 
submitted a revision to its 309 SIP, consisting of rules on emissions 
trading and smoke management, and a correction to the state's regional 
haze statutes, on December 31, 2004. EPA approved the smoke management 
rules submitted as part of the 2004 revisions, see 71 FR 28270 and 72 
FR 25973, but did not propose or take final action on any other portion 
of the 309 SIP.
    In response to an adverse court decision,\12\ EPA revised 40 CFR 
51.309 on October 13, 2006, making a number of substantive changes and 
requiring states to submit revised 309 SIPs by December 17, 2007. See 
71 FR 60612. Subsequently, ADEQ sent a letter to EPA dated December 14, 
2008, acknowledging that it had not submitted a SIP revision to address 
the requirements of 309(d)(4) related to stationary sources and 309(g), 
which governs reasonable progress requirements for Arizona's eight 
mandatory Class I areas outside of the Colorado Plateau.\13\
---------------------------------------------------------------------------

    \12\ Center for Energy and Economic Development v. EPA, 398 F.3d 
653 (D.C. Circuit 2005).
    \13\ Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA 
(December 14, 2008).
---------------------------------------------------------------------------

    EPA made a finding on January 15, 2009, that 37 states, including 
Arizona, had failed to make all or part of the required SIP submissions 
to address regional haze. See 74 FR 2392. Specifically, EPA found that 
Arizona failed to submit the plan elements required by 40 CFR 309(d)(4) 
and (g). EPA sent a letter to ADEQ on January 14, 2009, notifying the 
state of this failure to submit a complete SIP. ADEQ later decided to 
submit a SIP under section 308, instead of section 309.
    ADEQ adopted and transmitted its Regional Haze SIP under Section 
308 of the Regional Haze Rule (``Arizona Regional Haze SIP'') to EPA 
Region 9 in a letter dated February 28, 2011. The plan was determined 
complete by operation of law on August 28, 2011.\14\ The SIP was 
properly noticed by the State and available for public comment for 30 
days prior to a public hearing held in Phoenix, Arizona, on December 2, 
2010. Arizona included in its SIP responses to written comments from 
EPA Region 9, the National Park Service, the U.S. Forest Service, and 
other stakeholders including regulated industries and environmental 
organizations. The Arizona Regional Haze SIP is available to review in 
the docket for the proposed rule.
---------------------------------------------------------------------------

    \14\ See CAA section 110(k)(1)(B).
---------------------------------------------------------------------------

B. EPA's Authority To Promulgate a FIP

    Under CAA section 110(c), EPA is required to promulgate a Federal 
Implementation Plan within two years of the effective date of a finding 
that a state has failed to make a required SIP submission. The FIP 
requirement is void if a state submits a regional haze SIP, and EPA 
approves that SIP within the two-year period. See 74 FR 2392, January 
15, 2009. Specifically, CAA section 110(c) provides:
    (1) The Administrator shall promulgate a Federal implementation 
plan at any time within 2 years after the Administrator--
    (A) finds that a State has failed to make a required submission or 
finds that the plan or plan revision submitted by the State does not 
satisfy the minimum criteria established under [CAA section 
110(k)(1)(A)], or
    (B) disapproves a State implementation plan submission in whole or 
in part, unless the State corrects the deficiency, and the 
Administrator approves the plan or plan revision, before the 
Administrator promulgates such Federal implementation plan.
    Section 302(y) defines the term ``Federal implementation plan'' in 
pertinent part, as:

    [A] plan (or portion thereof) promulgated by the Administrator 
to fill all or a portion of a gap or otherwise correct all or a 
portion of an inadequacy in a State implementation plan, and which 
includes enforceable emission limitations or other control measures, 
means or techniques (including economic incentives, such as 
marketable permits or auctions or emissions allowances).

    Thus, because we determined that Arizona failed to timely submit a 
Regional Haze SIP, we are required to promulgate a Regional Haze FIP 
for Arizona, unless we first approve a SIP that corrects the non-
submittal deficiencies identified in our finding of January 15, 2009. 
For the reasons explained below, we are proposing to partially approve 
and partially disapprove the Arizona Regional Haze SIP. Therefore, we 
are proposing a FIP to address those portions of the SIP that we are 
proposing to disapprove. If Arizona submits a SIP revision that 
addresses the deficiencies in sufficient time for EPA to review the 
submission, then we would prefer to act on that submittal, if such 
action is consistent with our obligations under the CAA and applicable 
court orders.

VI. EPA's Evaluation of Arizona's BART Analyses and Determinations

 A. Arizona's Identification of BART Sources

    ADEQ's Analysis: In the first step of the BART process, ADEQ 
identified all the BART-eligible sources within the jurisdiction of the 
State and local agencies, and applied the three eligibility criteria in 
the RHR (40 CFR 51.301) to these facilities. The criteria are: (1) One 
or more emission units at the facility are classified in one of the 26 
industrial source categories listed in the BART Guidelines; (2) the 
emission unit(s) did not operate before August 7, 1962, but was in 
existence on August 7, 1977; and (3) the total potential to emit of any 
visibility impairing pollutant from the subject emission units is 
greater or equal to 250 tons per year. ADEQ determined that Apache, 
Cholla and Coronado have emissions units that meet these criteria.
    In a second step, ADEQ identified those BART-eligible sources that 
may reasonably be anticipated to cause or contribute to visibility 
impairment at any Class I area. The BART Guidelines allow states to 
consider exempting some BART-eligible sources from BART review in the 
event that they may not

[[Page 42840]]

reasonably be anticipated to cause or contribute to any visibility 
impairment in a Class I area. For states using modeling to determine 
the applicability of BART to single sources, the BART Guidelines note 
that the first step is to set a contribution threshold to assess 
whether the impact of a single source is sufficient to cause or 
contribute to visibility impairment at a Class I area. Further, the 
BART Guidelines state that, ``[a] single source that is responsible for 
a 1.0 deciview change or more should be considered to `cause' 
visibility impairment.'' \15\ The BART Guidelines also state that ``the 
appropriate threshold for determining whether a source contributes to 
visibility impairment' may reasonably differ across states,'' but, 
``[a]s a general matter, any threshold that you use for determining 
whether a source `contributes' to visibility impairment should not be 
higher than 0.5 deciviews.'' For determining whether a source is 
subject to BART, ADEQ used a contribution threshold of 0.50 dv.
---------------------------------------------------------------------------

    \15\ 70 FR 39104, 39161, July 6, 2005.
---------------------------------------------------------------------------

    The WRAP's Regional Modeling Center (RMC) developed a modeling 
protocol, entitled ``CALMET/CALPUFF Protocol for BART Exemption 
Screening Analysis for Class I Areas in the Western United States.'' 
\16\ The protocol specified the use of CALPUFF version 6.112 and CALMET 
version 6.211, which were the accepted model versions at the time.\17\ 
The WRAP RMC used this protocol to perform CALPUFF modeling for each of 
the western states. ADEQ then relied on the RMC's modeling to assess 
the potential of BART-eligible sources to cause or contribute to Class 
I visibility impairment. The visibility impacts of AEPCO Apache 
Generating Station, APS Cholla Power Plant, and SRP Coronado Generating 
Station are each well above the 0.5 dv ``contribution'' threshold as 
well as the 1.0 dv ``causation'' threshold.\18\ As a result, ADEQ 
determined that emissions units at the Apache, Cholla, and Coronado 
facilities are subject to BART as listed in Table 2.
---------------------------------------------------------------------------

    \16\ See Docket Item B-15.
    \17\ EPA subsequently required the uses of CALPUFF and CALMET 
version 5.8 for new modeling applications. However, EPA is accepting 
BART modeling performed according to a previously approved protocol, 
as was the case for the WRAP protocol.
    \18\ See Docket Item No. B-12. Visibility impacts as listed in 
``Summary of WRAP RMC BART Modeling for Arizona'' Draft No. 5, May 
7, 2005. Initial draft released on April 4, 2005.

                                        Table 2--Sources Subject to BART
----------------------------------------------------------------------------------------------------------------
                                                                                                         WRAP
            Facility                BART emission        Source category       Pollutants  evaluated    modeled
                                        units                                                         impact \a\
----------------------------------------------------------------------------------------------------------------
AEPCO Apache Generating Station  Units 1, 2, and 3.  Fossil-fuel fired steam  NOX, SO2, PM10........     1.95 dv
                                                      electric plants of
                                                      more than 250 million
                                                      British thermal units
                                                      per hour heat input.
APS Cholla Power Plant.........  Units 2, 3, and 4.  .......................  NOX, SO2, PM10........     2.88 dv
SRP Coronado Generating Station  Units 1 and 2.....  .......................  NOX, SO2, PM10........     3.32 dv
----------------------------------------------------------------------------------------------------------------
\a\ Average of the 98th percentile across 2001, 2002 and 2003 for the most affected Class I Area.

    EPA's Evaluation: We are proposing to approve ADEQ's determination 
that Apache, Cholla, and Coronado are eligible for and subject to a 
BART control analysis. Each of the three facilities addressed in this 
notice (Apache, Cholla and Coronado) agreed with ADEQ's determination 
that they are subject to BART. While we do not agree with all aspects 
of the process by which ADEQ identified its eligible-for-BART and 
subject-to-BART sources, we do agree with ADEQ that the three 
facilities in this notice are eligible for and subject to BART. Since 
our action today focuses on only the three facilities, we will address 
ADEQ's other subject-to-BART determinations in a separate action at a 
later date.

B. Arizona's BART Control Analysis

    The third step of the BART evaluation is to perform a five-factor 
BART analysis as the basis for making a BART control determination. In 
performing this analysis, 40 CFR 51.308(e)(1)(ii)(A) requires that 
states consider the following factors on a pollutant-by-pollutant 
basis: (1) The costs of compliance of each technically feasible control 
technology, (2) the energy and non-air quality environmental impacts of 
compliance of the control technologies, (3) any existing pollution 
control technology in use at the source, (4) the remaining useful life 
of the source, and (5) the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology. These factors are frequently referred to as the ``five-
factor analysis'' for the RHR BART determination.
    The BART Guidelines recommend that a BART analysis include the 
following five steps. The Guidelines provide detailed instructions on 
how to perform each of these steps.\19\
---------------------------------------------------------------------------

    \19\ 40 CFR part 51, appendix Y, Sec.  IV.D.

 Step 1--Identify All Available Retrofit Control Technologies,
 Step 2--Eliminate Technically Infeasible Options,
 Step 3--Evaluate Control Effectiveness of Remaining Control 
Technologies,
 Step 4--Evaluate Impacts and Document the Results,\20\ and
---------------------------------------------------------------------------

    \20\ Step 4 includes evaluating the cost of compliance, energy 
impacts, non-air quality environmental impacts, and remaining useful 
life.
---------------------------------------------------------------------------

 Step 5--Evaluate Visibility Impacts.

    ADEQ's Analysis: ADEQ's BART analyses mostly followed this 
approach, with the addition of a step to identify existing control 
technologies and a step concluding ``selection of BART.'' \21\ Thus, 
ADEQ's analyses included the following seven steps:
---------------------------------------------------------------------------

    \21\ Arizona Regional Haze SIP, pp. 138-143.

 Step 1: Identify the Existing Control Technologies in Use at 
the Source
 Step 2: Identify All Available Retrofit Control Options
 Step 3: Eliminate All Technically Infeasible Control Options
 Step 4: Evaluate Control Effectiveness of Remaining 
Technologies
 Step 5: Evaluate the Energy and Non-Air Quality Environmental 
Impacts and Document Results \22\
---------------------------------------------------------------------------

    \22\ We note that, while ADEQ refers to its Step 5 as an 
evaluation of energy and non-air quality environmental impacts, this 
step also includes consideration of the costs of compliance and the 
remaining useful life of the source, consistent with the BART 
Guidelines, 40 CFR part 51, appendix Y, Sec.  IV.D.4.
---------------------------------------------------------------------------

 Step 6: Evaluate Visibility Impacts
 Step 7: Select BART

    EPA's Evaluation: We find that this overall approach to the five-
factor analysis is generally reasonable and consistent with the RHR and 
the BART Guidelines. With respect to the three

[[Page 42841]]

sources covered by this action, we find that ADEQ's implementation of 
the first four steps of its approach is generally reasonable and 
consistent with the RHR and the BART Guidelines. However, we do not 
agree with ADEQ's analysis in steps 5 through 7.\23\ In particular, 
under step 5, we find that the costs of control were not calculated in 
accordance with the BART Guidelines; under step 6, we find that the 
visibility impacts were not appropriately evaluated and considered; and 
under step 7, we find that ADEQ did not provide a sufficient 
explanation and rationale for its determinations. While we find these 
problems in all of ADEQ's BART analyses for the three sources, they do 
not appear to have had a substantive impact on ADEQ's selection of 
controls for SO2 and PM10. With respect to ADEQ's 
NOX BART determinations, however, we find that these 
problems resulted in control determinations that are inconsistent with 
the RHR and the BART Guidelines. We summarize below how ADEQ applied 
the five factors and identify a number of issues common to the three 
relevant sources.
---------------------------------------------------------------------------

    \23\ We do not believe that ADEQ appropriately used ``the most 
stringent emission control level that the technology is capable of 
achieving'' for SCR per the BART Guidelines at 40 CFR part 51, 
appendix Y, Sec.  IV.D.3. This issue is addressed on a source-by-
source basis under the cost and visibility factors of our evaluation 
in section VI.C.
---------------------------------------------------------------------------

1. Cost of Compliance
    ADEQ included information relating to costs of compliance in its RH 
SIP, including information on total annualized costs, cost per ton of 
pollutant removed, and incremental cost per ton of pollutant removed 
for the various control options considered. Cost calculations were 
prepared by consulting firms on behalf of the facilities as part of 
their BART analyses that relied on a combination of vendor quotes, 
facility data, and internal cost calculation methodology. These BART 
analyses were subsequently submitted to ADEQ. Upon review, ADEQ 
requested certain clarifying information from the facilities regarding 
these cost calculations, including greater detail on the underlying 
assumptions and additional supporting documentation. ADEQ received 
responses of varying detail to these requests, and included this 
information as part of its RH SIP. As described in further detail in 
the discussion of each facility, there are certain aspects of these 
cost calculations that we find inconsistent with the BART Guidelines 
and EPA's Control Cost Manual. We also disagree with the manner in 
which ADEQ interpreted the cost-related information included in its RH 
SIP.
2. Energy and Non-Air Quality Environmental Impacts
    In its BART analyses, ADEQ identified only minor energy and non-air 
quality impacts for SO2 or PM10 control 
strategies. Regarding NOX emissions, ADEQ's BART analyses 
point out that the various control options will incur increased energy 
usage by any electric generating unit (EGU) where they are installed. 
In particular, Selective Catalytic Reduction (SCR) retrofit will cause 
an additional pressure drop in the flue gas system due to the catalyst, 
increasing power requirements. Additionally, ADEQ's SIP submission 
asserts that ammonia levels in fly ash due to Selective Non-catalytic 
Reduction (SNCR) and SCR installations could affect the decision of 
facility managers to sell or dispose of fly ash.\24\ Finally, the 
Arizona SIP notes that SNCR and SCR may involve potential safety 
hazards associated with the transportation and handling of anhydrous 
ammonia.\25\ However, ADEQ did not cite any of these potential energy 
and non-air impacts as the basis for eliminating any otherwise feasible 
control strategies for NOX. EPA concurs that these impacts 
do not warrant elimination of any of the control options.
---------------------------------------------------------------------------

    \24\ Arizona Regional Haze SIP, Appendix D, p. 63.
    \25\ See, e.g. id. p. 53.
---------------------------------------------------------------------------

3. Existing Pollution Control Technology
    The presence of existing pollution control technology is reflected 
in the BART analysis in two ways: First, in the consideration of 
available control technologies (step 1 of ADEQ's analysis), and second, 
in the development of baseline emission rates for use in cost 
calculations and visibility modeling (steps 5 and 6 of ADEQ's 
analysis). As described in greater detail in the discussion for each 
facility, AEPCO, APS, and SRP used baseline time periods that varied 
from 2001 to 2007. The respective baseline emissions and existing 
pollution control technology used in the BART analyses reflect the 
levels of control in place at the time. EPA considers ADEQ's approach 
to be reasonable and generally consistent with the RHR and the BART 
Guidelines.
4. Remaining Useful Life of the Source
    The remaining useful life of the source is usually considered as a 
quantitative factor in estimating the cost of compliance. With the 
exception of Apache Generating Station Unit 1, ADEQ used the default 
20-year amortization period in the EPA Cost Control Manual as the 
remaining useful life of the facilities in its RH SIP. Without 
commitments for an early shut down of an EGU, it is not appropriate to 
consider a shorter amortization period in a BART analysis.
5. Degree of Visibility Improvement
    ADEQ assessed the degree of improvement in visibility from 
candidate BART technologies using models and procedures generally in 
accord with EPA guidance. ADEQ relied on visibility analysis performed 
by the facilities, which used the WRAP RMC's modeling protocol. 
However, ADEQ's use of the modeling results in making BART decisions is 
problematic in several respects. First, ADEQ appears to have considered 
the visibility benefit of controls at only a single Class I area for 
each facility, even though there are nine to seventeen Class I areas 
nearby, depending on the facility. Since the facilities' modeling 
results indicated that controls would contribute to visibility 
improvement in multiple Class I areas, consideration of the benefits in 
additional areas is warranted. Although the RHR and the BART Guidelines 
do not prescribe a particular approach to calculating or considering 
visibility benefits across multiple Class I areas, overlooking 
significant visibility benefits at additional areas considerably 
understates the overall benefit of controls to improve visibility. A 
more complete assessment of the degree of visibility improvement for 
candidate BART controls would include consideration of the number of 
areas affected and the degree of visibility improvement expected in all 
areas. One could conduct this type of analysis by summing the benefits 
over the areas, or by some other quantitative or qualitative 
procedure.\26\ The procedure followed by ADEQ is not a sufficient basis 
for making BART determinations for sources with substantial benefits 
across many Class I areas.
---------------------------------------------------------------------------

    \26\ Note that the issue here is not whether an individual in a 
given time and place would perceive the deciview benefits occurring 
at different Class I areas and under possibly different 
meteorological conditions. Rather, the issue is accounting in some 
way for the full set of expected visibility benefits. A national 
program for addressing regional haze must inherently address the 
multiple areas that occur in a region.
---------------------------------------------------------------------------

    Second, ADEQ appears to have considered benefits from controls on 
only one emitting unit at a time. However, because the plumes from 
individual units overlap more or less completely by the time they reach 
a

[[Page 42842]]

Class I area, the visibility benefits from controls on multiple units 
would be approximately additive. This issue of additive unit benefits 
could be addressed in some way without modeling all the units together, 
but ADEQ does not appear to have done this, and therefore 
underestimated the degree of visibility improvement from controls.
    Finally, the ammonia background concentration assumed for Cholla 
and Coronado may be too low, ranging from 1 ppb to as low as 0.2 ppb. 
Nitrogen oxides and SO2 emissions affect visibility after 
chemically transforming into particulate ammonium nitrate and ammonium 
sulfate, respectively. This process is limited by the amount of ammonia 
present, so modeling with a low assumed ammonia background may 
underestimate visibility impacts and thus the visibility benefit of 
controls. Ambient ammonia measurements for use as input to modeling are 
scarce, and measurements that include it in the form of ammonium even 
scarcer. In the absence of compelling ammonia background estimates, EPA 
guidance recommends the use of a 1 ppb ammonia background for areas in 
the west.\27\
---------------------------------------------------------------------------

    \27\ Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 
2 Summary Report and Recommendations for Modeling Long Range 
Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998, 
http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
---------------------------------------------------------------------------

 C. Arizona's BART Determinations

    Our evaluation of ADEQ's BART determinations is organized by 
source, unit and pollutant with a focus on the cost and visibility 
factors of the BART analysis. A summary of the State's BART 
determinations for the three sources is in Table 3. ADEQ's BART 
determinations for NOX consist of combustion controls, 
either in the form of low-NOX burners (LNB) with flue gas 
recirculation (FGR), or LNB with overfire air (OFA) or separated 
overfire air (SOFA). For PM10, ADEQ's BART determinations 
consist of fuel switching to pipeline natural gas (PNG) for Apache Unit 
1, and add-on particulate controls such as electrostatic precipitators 
(ESPs) or fabric filters for the remaining units. For SO2, 
ADEQ's BART determinations consist of fuel-switching to PNG for Apache 
Unit 1, and wet flue gas desulfurization (FGD) systems that are either 
already in place or planned for the remaining units.

                                                    Table 3--Summary of Arizona's Bart Determinations
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           NOX                            PM10                           SO2
                                   Size                      -------------------------------------------------------------------------------------------
              Unit                 (MW)          Fuel               Control        Emission        Control        Emission       Control        Emission
                                                                  technology       limit *       technology       limit *       technology      limit *
--------------------------------------------------------------------------------------------------------------------------------------------------------
Apache 1.......................       75  Natural Gas.......  LNB w/FGR, PNG use      0.056  PNG use...........     0.0075  PNG use..........    0.00064
Apache 2.......................      195  Coal..............  LNB w/OFA.........       0.31  ESP (upgraded)....       0.03  Wet FGD                 0.15
                                                                                                                             (existing).
Apache 3.......................      195  Coal..............  LNB w/OFA.........       0.31  ESP (upgraded)....       0.03  Wet FGD                 0.15
                                                                                                                             (existing).
Cholla 2.......................      305  Coal..............  LNB w/SOFA........       0.22  Fabric filter.....      0.015  Wet FGD                 0.15
                                                                                                                             (existing).
Cholla 3.......................      305  Coal..............  LNB w/SOFA........       0.22  Fabric filter           0.015  Wet FGD                 0.15
                                                                                              (existing).                    (existing).
Cholla 4.......................      425  Coal..............  LNB w/SOFA........       0.22  Fabric filter           0.015  Wet FGD                 0.15
                                                                                              (existing).                    (existing).
Coronado 1.....................      411  Coal..............  LNB w/OFA.........       0.32  Hot-side ESP......       0.03  Wet FGD (per            0.08
                                                                                                                             Consent Decree).
Coronado 2.....................      411  Coal..............  LNB w/OFA.........       0.32  Hot-side ESP......       0.03  Wet FGD (per            0.08
                                                                                                                             Consent Decree).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Emission limits are in lb/MMBtu.

 1. Apache Unit 1
    Apache Generating Station (Apache) consists of seven EGUs with a 
total plant-wide generating capacity of 560 megawatts. Unit 1 is a 
wall-fired boiler with a net unit output of 85 MW that burns pipeline-
quality natural gas as its primary fuel, but also has the capability to 
use No. 2 through No. 6 fuel oils. At present, no emissions control 
equipment is installed on Unit 1. ADEQ's BART analyses for Apache Unit 
1 relied largely on data and analyses provided by AEPCO and its 
contractor. These data and analyses are summarized below, along with 
ADEQ's determinations for each pollutant and EPA's evaluations of these 
analyses and determinations.
a. BART for NOX
    ADEQ's Analysis: Unit 1 currently operates with no NOX 
controls. In its BART analysis submitted to ADEQ, AEPCO developed 
baseline emissions for multiple fuel-use scenarios including natural 
gas, and No. 2 and No. 6 fuel oil usage. Baseline natural gas emissions 
were based on the highest 75 percent load 24-hour NOX 
emission levels reported in EPA's Acid Rain Database for 2006. Since 
the only fuel burned in 2006 was natural gas, baseline emissions for 
No. 2 or No. 6 fuel oil usage could not be developed based on data from 
2006. As a simplifying assumption, baseline No. 2 fuel oil 
NOX emissions were assumed to be equal to natural gas usage. 
Baseline emissions for No. 6 fuel oil usage were estimated using AP-42 
emission factors.\28\ A summary of baseline emissions for various fuels 
is provided in Table 4.
---------------------------------------------------------------------------

    \28\ See Docket Item B-2. Page 2-1 of AEPCO Apache 1 BART 
Analysis.

      Table 4--Apache Unit 1: Arizona's Baseline Emission Factors a
------------------------------------------------------------------------
                                Natural  Gas   No. 2  Fuel   No. 6  fuel
          Pollutant              (lb/MMBtu)        oil           oil
------------------------------------------------------------------------
NOX..........................         0.147          0.147        0.301
PM10.........................         0.0075         0.014        0.0737
SO2..........................         0.00064        0.051        0.906
------------------------------------------------------------------------
a See Docket Item B-02 (Table 3-1 of AEPCO Apache 1 BART Analysis).


[[Page 42843]]

    AEPCO examined multiple control technologies and options for Apache 
Unit 1, including combustion controls, post combustion add-on controls, 
and fuel-switching. A summary of cost of compliance and degree of 
visibility improvement for these options is in Table 5. These cost and 
visibility improvement values are based on baseline and control case 
emissions corresponding to No. 6 fuel oil usage, which of the three 
fuels considered is the fuel type that generates the greatest 
NOX emissions.

                                         Table 5--Apache Unit 1: Arizona's Cost and Visibility Analysis for NOX
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                            Cost- effectiveness d ($/ton)  Visibility Improvement c (dv)
                                                       Emission    Emissions    Annualized -------------------------------------------------------------
                  Control option b                    rate (lb/     removed      cost ($/                   Incremental    Total (from     Incremental
                                                        MMBtu)     (tons/yr)      year)       Average    (from  previous)   base case)  (from  previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline...........................................        0.301  ...........  ...........  ...........  ................  ...........  ................
LNB + FGR..........................................         0.15          297      551,982        1,859  ................        0.194  ................
ROFA...............................................         0.16          278      939,093        3,378           -20,374        0.256             0.062
SNCR with LNB + FGR................................         0.11          376    1,079,389        2,871             1,432         0.24            -0.016
ROFA w/Rotamix.....................................         0.11          376    1,505,825        4,005              a NA         0.24              a NA
SCR with LNB + FGR.................................         0.07          455    5,704,798       12,538            53,152        0.409             0.169
--------------------------------------------------------------------------------------------------------------------------------------------------------
a The previous option, SNCR with LNB + FGR has the same emission rate, making an incremental comparison invalid.
b Per ADEQ's and AEPCO's analyses, control options are ranked here by cost, not by emission rate
c Visibility improvement at Chiricahua Wilderness Area, the Class I area exhibiting the highest impact
d Cost-effectiveness values obtained from Table 10.3, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.

    In its cost calculations for Apache Unit 1, AEPCO used a capital 
recovery factor based on a 7.10 percent interest rate, and a plant 
remaining useful life of eight years.\29\ The plant's remaining useful 
life was based upon Apache Unit 1 operating until 2021, and an assumed 
BART implementation date of 2013.\30\ AEPCO eliminated many control 
options, including SCR, based on high cost-effectiveness ($/ton), and 
primarily examined the LNB w/FGR and ROFA control options. AEPCO noted 
that LNB with FGR resulted in larger incremental visibility improvement 
than ROFA, and proposed LNB with FGR, burning either natural gas or 
fuel oil, as BART for NOX at Apache Unit 1.
---------------------------------------------------------------------------

    \29\ See Docket Item B-02. Appendix A (Economic Analysis) of 
AEPCO Apache 1 BART Analysis.
    \30\ See Docket Item B-02. Page 2-1 of AEPCO Apache 1 BART 
Analysis.
---------------------------------------------------------------------------

    In order to evaluate AEPCO's BART analysis, ADEQ requested 
supporting information explaining assumptions used in the economic 
analysis, baseline emissions, and control technology options. Based on 
this additional information, as well as on AEPCO's original analysis, 
ADEQ accepted the company's proposed BART recommendation of LNB with 
FGR for Unit 1, but added a fuel restriction to allow only the use of 
natural gas. This determination corresponds to a BART emission limit 
for NOX at Apache Unit 1 of 0.056 lb/MMBtu.\31\
---------------------------------------------------------------------------

    \31\ See Docket Item B-01. Emission rate as specified in Table 
10.2, Appendix D (Technical Support Document) of Arizona Regional 
Haze SIP.
---------------------------------------------------------------------------

    EPA's Evaluation: We disagree with multiple aspects of the analysis 
for Apache Unit 1. We consider the use of eight years for the plant's 
remaining useful life in the control cost calculations as unjustified 
in the absence of documentation that the unit will shut down in 2021. 
We also note that control cost calculations include costs that are 
disallowed by EPA's Control Cost Manual, such as owner's costs and 
AFUDC. Both of these elements have the effect of inflating cost 
calculations and thus the cost-effectiveness of the various control 
options considered. In addition, we do not consider using identical 
baseline emissions for No. 2 fuel oil and natural gas appropriate, 
although this likely did not affect either AEPCO's or ADEQ's BART 
determination, which was informed primarily by emission estimates based 
on No. 6 fuel oil, the highest emitting fuel.
    By including a natural gas-only fuel restriction, ADEQ's BART 
determination of LNB with FGR results in a NOX emissions 
limit of 0.056 lb/MMBtu, which is more stringent than any of the 
control options that AEPCO and ADEQ considered in conjunction with No. 
6 or No. 2 fuel oil. Neither AEPCO's nor ADEQ's analysis, however, 
included visibility modeling for control options on a natural gas-only 
basis. The absence of such information does not allow us to fully 
evaluate if options more stringent than LNB with FGR are appropriate on 
a natural gas-only basis. Nevertheless, we are proposing to approve 
ADEQ's NOX BART determination of LNB with FGR (natural gas 
usage only) with an emission limit of 0.056 lb/MMBtu for Apache Unit 1.
b. BART for PM10
    ADEQ's Analysis: Apache Unit 1 currently operates with no 
PM10 controls. In its BART analysis submitted to ADEQ, AEPCO 
developed baseline emissions for multiple fuel use scenarios including 
natural gas, and No. 2 and No. 6 fuel oil usage. Baseline 
PM10 emissions for all fuels were calculated based on AP-42 
emission factors.\32\ A summary of these emissions is in Table 4.
---------------------------------------------------------------------------

    \32\ See Docket Item B-02, Page 2-1 of AEPCO Apache 1 BART 
Analysis.
---------------------------------------------------------------------------

    AEPCO examined multiple control options for PM10 at 
Apache Unit 1, including add-on controls and fuel switching. A summary 
of cost of compliance and degree of visibility improvement for these 
options is summarized in Table 6. These cost and visibility improvement 
values are based on baseline and control case emissions corresponding 
to No. 6 fuel oil usage, which of the three fuels considered generates 
the greatest PM10 emissions. In its BART analysis, AEPCO 
cited high costs of compliance and minimal visibility improvements for 
the PM10 control options, and proposed no PM10 
controls as BART for PM10, using either natural gas or No. 2 
fuel oil. Based on the data and analysis provided by AEPCO, ADEQ 
determined that BART for PM10 at Apache Unit 1 is no 
additional controls, but also determined that a fuel restriction to 
allow only the use of natural gas was appropriate. This corresponds to 
a PM10 BART emission

[[Page 42844]]

limit for Apache Unit 1 of 0.0075 lb/MMBtu.\33\
---------------------------------------------------------------------------

    \33\ See Docket Item B-01. Emission rate as specified in Table 
10.5, Appendix D (Technical Support Document) of Arizona Regional 
Haze SIP.

                                         Table 6--Apache Unit 1: Arizona's Cost and Visibility Analysis for PM10
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                       Cost-effectiveness \a\    Visibility Improvement
                                                                                                               ($/ton)                  \b\ (dv)
                                                                 Emission    Emissions    Annualized ---------------------------------------------------
                        Control option                          rate (lb/     removed      cost ($/                Incremental     Total     Incremental
                                                                  MMBtu)     (tons/yr)      year)       Average        (from     (from base      (from
                                                                                                                    previous)      case)      previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline.....................................................       0.0737  ...........  ...........  ...........  ...........  ...........  ...........
Fabric Filter................................................        0.015          116    3,615,938       31,172  ...........        0.010  ...........
Fuel switch to PNG...........................................       0.0075  ...........            0  ...........  ...........  ...........  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Cost-effectiveness values as reported in Table 10.6, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.
b As summarized in Table 5-12, AEPCO Apache 1 BART Analysis. See Docket Item B-02. Visibility improvement at Chiricahua Wilderness Area, the Class I
  area exhibiting the highest impact.

    EPA's Evaluation: ADEQ's PM10 analysis includes many of 
the same issues we noted in its NOX analysis, including the 
use of an eight-year plant remaining useful life, and inclusion of 
costs that are disallowed by EPA's Control Cost Manual. Although we do 
not agree with elements of ADEQ's PM10 BART analysis for 
Apache Unit 1, we find that its conclusion is reasonable, given the 
small visibility improvement projected to result from PM10 
reductions at this Unit. Thus, we are proposing to approve ADEQ's 
PM10 BART determination for Apache Unit 1.
c. BART for SO2
    ADEQ's Analysis: Apache Unit 1 currently operates with no 
SO2 controls. In its BART analysis submitted to ADEQ, AEPCO 
developed baseline emissions for multiple fuel use scenarios including 
natural gas, and No. 2 and No. 6 fuel oil. Baseline natural gas 
emissions were based upon the highest 75 percent load 24-hour 
SO2 emission levels reported in EPA's Acid Rain Database for 
2006. Since the only fuel burned in 2006 was natural gas, baseline 
emissions for No. 2 or No. 6 fuel oil usage could not be developed 
based on data from 2006. Baseline emissions for No. 2 and No. 6 fuel 
oil usage were estimated using AP-42 emission factors.\34\ A summary of 
these emissions is summarized in Table 4.
---------------------------------------------------------------------------

    \34\ See Docket Item B-02. Page 2-2 of AEPCO Apache 1 BART 
Analysis.
---------------------------------------------------------------------------

    AEPCO also examined multiple control options for SO2 on 
Apache 1, including add-on controls and fuel-switching. A summary of 
cost of compliance and degree of visibility improvement for these 
options is summarized in Table 7. These cost and visibility improvement 
values are from baseline and control case emissions corresponding to 
No. 6 fuel oil usage, which is the fuel type that generates the 
greatest SO2 emissions. In its BART analysis, AEPCO cited 
high costs of compliance and minimal visibility improvements for the 
SO2 control options, and proposed no additional 
SO2 controls, using either natural gas or No. 2 fuel oil, as 
BART for SO2. ADEQ determined that BART for SO2 
is no additional controls, but added a fuel restriction to allow only 
the use of natural gas. This corresponds to an SO2 BART 
emission limit for Apache Unit 1 of 0.00064 lb/MMBtu.\35\
---------------------------------------------------------------------------

    \35\ See Docket Item B-01. Emission rate as specified in Table 
10.7, Appendix D (Technical Support Document) of Arizona Regional 
Haze SIP.

                                         Table 7--Apache Unit 1: Arizona's Cost and Visibility Analysis for So2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Cost-effectiveness a ($/    Visibility Improvement b
                                                                                                             ton)                        (dv)
                                                              Emission    Emissions    Annualized ------------------------------------------------------
                      Control option                         rate (lb/     removed      cost ($/                Incremental     Total       Incremental
                                                               MMBtu)     (tons/yr)      year)       Average        (from     (from base       (from
                                                                                                                 previous)      case)        previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline..................................................        0.906  ...........  ...........  ...........  ...........  ...........  ..............
Fuel switch to low-sulfur fuel oil........................        0.051  ...........  ...........  ...........  ...........  ...........  ..............
Spray dryer absorber (dry FGD) 1..........................         0.10        1,587    3,881,706        2,446  ...........        0.765  ..............
Fuel switch to PNG........................................      0.00064  ...........            0  ...........  ...........  ...........  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Cost-effectiveness values as reported in Table 10.8, Appendix D (TSD) of Arizona RH SIP. See Docket Item B-01.
b As summarized in Table 5-12, AEPCO Apache 1 BART Analysis. See Docket Item B-02. Visibility improvement at Chiricahua Wilderness Area, the Class I
  area exhibiting the highest impact.

    EPA's Evaluation: The SO2 analysis includes many of the 
same issues we noted in the NOX analysis, including the use 
of an eight-year plant remaining useful life, and inclusion of costs 
that are disallowed by EPA's Control Cost Manual. ADEQ's BART 
determination, requiring the use of only natural gas, results in an 
SO2 emission limit of 0.00064 lb/MMBtu. This emission rate 
is more stringent than any of the control options that ADEQ considered 
in conjunction with No. 6 fuel oil. We are proposing to approve ADEQ's 
BART determination for SO2 as an emission limit of 0.00064 
lb/MMBtu at Apache Unit 1.
2. Apache Units 2 and 3
    Apache Units 2 and 3 are both dry-bottom, Riley Stoker turbo-fired 
boilers, each with a gross unit output of 204 MW. Both units are BART-
eligible and are coal-fired boilers operating on sub-bituminous coal. 
Although there are physical differences between the two units, ADEQ 
found that the overall

[[Page 42845]]

differences are minimal and therefore considered both units together in 
its BART analysis. As with Apache Unit 1, ADEQ's analysis relied 
largely on information provided by AEPCO and its contractor. This 
information is summarized below, along with ADEQ's determinations for 
each pollutant and EPA's evaluation.
    While the following sections describe both ADEQ's and EPA's 
evaluations based on the information in the record, we note that we 
received additional information from AEPCO on June 29, 2012, related to 
the potential adverse impacts of the affordability of NOX 
controls. AEPCO states that affordability is affected by its small 
size, the low income profiles of AEPCO's service area, and AEPCO's 
ability to access financing. While this information came in too late to 
be evaluated as part of this proposed rulemaking, EPA has put the 
information in the docket and will evaluate it during the public 
comment period.\36\
---------------------------------------------------------------------------

    \36\ See Docket Item C-16, Letter from Michelle Freeark (AEPCO) 
to Deborah Jordan (EPA), AEPCO's Comments on BART for Apache 
Generating Station, June 29, 2012.
---------------------------------------------------------------------------

a. BART for NOX
    ADEQ's Analysis: AEPCO developed baseline NOX emissions 
by examining the average NOX emissions from 2002 to 2007, a 
time period in which both units were equipped with OFA as 
NOX emission controls.\37\ AEPCO examined several 
NOX control technologies, including combustion controls and 
add-on post-combustion controls. A summary of Arizona's costs of 
compliance and visibility impacts associated with these options is 
presented in Table 8. ADEQ relied on this information from the facility 
to develop its RH SIP.\38\ Estimates of control technology emission 
rates were developed based on a combination of vendor quotes, 
contractor information, and internal AEPCO information regarding 
environmental upgrades.\39\ Annual emission reductions were calculated 
based on the emission rate estimates combined with annual capacity 
factors as specified by AEPCO.\40\ Control costs were developed based 
on a combination of vendor quotes and contractor information. These 
cost calculations provided line item summaries of capital costs and 
annual operating costs, but did not include further supporting 
information such as detailed equipment lists, vendor quotes, or the 
design basis for line item costs.
---------------------------------------------------------------------------

    \37\ See Docket Item B-03 and B-04, AEPCO Apache BART Analyses, 
page 2-2.
    \38\ See Docket Item B-03 and B-04, AEPCO Apache BART Analyses. 
This information is also summarized in Docket Item B-01, Arizona 
Regional Haze SIP, Appendix D, Tables 10.10 through 10.13.
    \39\ As listed in Table 3-2, Docket Items B-03 and B-04, AEPCO 
Apache BART Analyses.
    \40\ As listed in Table 2-1, Docket Items B-03 and B-04. Annual 
capacity factors used for each unit are 92% (Apache 2), and 87% 
(Apache 3).

                                          Table 8--Apache Units 2 and 3: Arizona's Cost and Visibility Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Cost-effectiveness ($/   Visibility improvement
                                                                                                    ton)               \a\ (deciviews)        Cost per
                                                     Emission    Emissions   Annualized  --------------------------------------------------     total
                  Control option                     rate (lb/    removed     cost ($/                Incremental     Total    Incremental    deciview
                                                      MMBtu)     (tons/yr)      year)       Average       (from       (from        (from     improvement
                                                                                                       previous)    baseline)   previous)      ($/dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Apache Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)....................................        0.47  ..........  ............  ..........  ...........  ..........  ...........  ............
LNB + OFA.........................................        0.31       1,305      $533,000        $408  ...........       0.267  ...........    $1,996,000
ROFA..............................................        0.26       1,710     1,664,000         973          305       0.359        0.092     4,636,000
SNCR + LNB + OFA..................................        0.23       1,953     1,738,000         890        1,860       0.416        0.057     4,532,000
ROFA w/Rotamix....................................        0.18       2,358     2,225,000         944          866       0.491        0.075     4,177,000
SCR + LNB + OFA...................................        0.07       3,250     6,102,000       1,878        4,346       0.676        0.185     9,028,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Apache Unit 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)....................................        0.43  ..........  ............  ..........  ...........  ..........  ...........  ............
LNB + OFA.........................................        0.31         926       532,808         575  ...........       0.206  ...........     2,586,000
ROFA..............................................        0.26       1,312     1,643,241       1,252          322       0.298        0.092     5,484,000
SNCR + LNB + OFA..................................        0.23       1,543     1,717,633       1,113        1,920       0.356        0.058     5,004,000
ROFA w/Rotamix....................................        0.18       1,929     2,181,833       1,131          873       0.436        0.080     4,825,000
SCR + LNB + OFA...................................        0.07       2,778     6,062,301       2,182        4,571       0.633        0.197     9,577,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ At the Class I area exhibiting the greatest baseline visibility impact, Chiricahua Wilderness Area.

    Regarding visibility impacts, ADEQ relied on visibility modeling 
submitted by AEPCO to evaluate the visibility improvement attributable 
to each of the NOX control technologies that it considered. 
This visibility modeling was performed using three years of 
meteorological data (2001 to 2003), and was generally performed in 
accordance with the WRAP modeling protocol. The average of the three 
98th percentiles from the modeled years 2001 to 2003 was used as the 
visibility metric for each emission scenario and Class I area. For 
assessing the degree of visibility improvement, ADEQ considered only 
the visibility benefits at the area with the highest base case (pre-
control) impact: Chiricahua National Monument and Chiricahua Wilderness 
Area (two nearby Class I areas served by one air monitor). For each 
control, ADEQ listed visibility improvement in deciviews, and cost in 
millions of dollars per deciview improvement.\41\ Results are 
comparable for both units, with Unit 2 showing somewhat higher 
visibility benefits and somewhat lower cost per improvement than Unit 
3. Unit 2 visibility improvements range from 0.27 dv for LNB to 0.68 dv 
for SCR, while the costs per deciview range from $2 million for LNB to 
over $9 million for SCR. ADEQ concluded that LNBs with the existing OFA 
systems represent BART for Units 2 and 3, though no explicit reasoning 
is provided for the selection.
---------------------------------------------------------------------------

    \41\ Arizona SIP submittal, ``Appendix D: Arizona BART--
Supplemental Information'', p. 65.
---------------------------------------------------------------------------

    ADEQ determined that LNB plus OFA constitute BART for 
NOX at Apache Units 2 and 3. In making this determination, 
ADEQ did not provide adequate information regarding its rationale or 
weighing of the five factors. ADEQ stated only that ``(A)fter reviewing 
the company's BART analysis, and based upon the information above, ADEQ 
has

[[Page 42846]]

determined that, for Units 2 and 3 BART for NOX is new LNBs 
and the existing OFA system with a NOX emissions limit of 
0.31 lb/MMBtu * * *.'' \42\
---------------------------------------------------------------------------

    \42\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D, 
Page 65.
---------------------------------------------------------------------------

    EPA's Evaluation: We disagree with several aspects of the 
NOX BART analysis for Apache Units 2 and 3. The control cost 
calculations included line item costs not allowed by the EPA Control 
Cost Manual, such as owner's costs, surcharge, and AFUDC. Inclusion of 
these line items has the effect of inflating the total cost of 
compliance and the cost per ton of pollutant reduced.
    Regarding visibility improvement as shown in Table 8, ADEQ chose 
LNB as BART, which provides the lowest visibility benefit of any of the 
controls modeled. By contrast, SCR would provide an improvement of more 
than 0.5 dv at a single Class I Area, and a substantial incremental 
benefit relative to the next more stringent control, ROFA-Rotamix. 
Multiple Class I areas have comparable benefits. The visibility 
benefits are larger than those listed, if both Units 2 and 3 are 
considered together. (See Table 17 below for EPA's visibility results.) 
The SCR cost per deciview of improvement is lower than those for Cholla 
and Coronado, as indicated below in their respective sections.
    ADEQ provides little explicit reasoning about the visibility basis 
for the BART selection. For example, there is no weighing of visibility 
benefits and visibility cost-effectiveness for the various candidate 
controls and the various Class I areas. The modeling results show that 
controls more stringent than LNB appear to be needed to give 
substantial visibility benefits. Visibility impacts at eight nearby 
Class I areas were not considered, and the visibility benefits of 
simultaneous controls on both units were not considered. For these 
reasons, EPA believes that ADEQ gave insufficient consideration to the 
visibility benefits of the various NOX control options 
available at Apache Units 2 and 3.
    In summary, we find that ADEQ has not provided an adequate 
justification for adopting LNB with OFA as the ``best'' level of 
control.\43\ Although ADEQ has developed information regarding each of 
the five factors, there are problems in both its cost and visibility 
analyses as described above. Moreover, ADEQ's BART analysis does not 
explain how it weighed these factors. For example, ADEQ did not 
indicate whether or not it considered any cost thresholds to be 
reasonable or expensive in analyzing the costs of compliance for the 
various control options. We note that ADEQ has made similar 
NOX BART determinations of LNB with OFA at other facilities, 
such as Cholla Power Plant. Although ADEQ's BART determinations for 
these other facilities implied that cost of compliance was an important 
consideration, it does not provide a rationale for this selection of 
NOX BART.\44\ Thus, we are proposing to disapprove ADEQ's 
BART determination for NOX at Apache Units 2 and 3, since it 
does not comply with 40 CFR 51.308(e)(1)(ii)(A).
---------------------------------------------------------------------------

    \43\ See BART Guidelines, Sec.  IV.E.2.
    \44\ We do note, however, that AEPCO does provide some 
additional analysis on this position in the Apache BART analyses it 
submitted to ADEQ. Aside from stating that it reviewed AEPCO's 
analysis, ADEQ did not specifically reference or include any aspects 
of AEPCO's analysis in the RH SIP. As a result, we are not assuming 
that ADEQ necessarily agrees with AEPCO's rationale, and have 
therefore not provided an evaluation of it.
---------------------------------------------------------------------------

b. BART for PM10
    ADEQ's Analysis: The existing PM10 controls on Apache 
Units 2 and 3 are hot-side Electrostatic Precipitators (ESPs).\45\ 
AEPCO and ADEQ considered three potential retrofit control options for 
PM10:
---------------------------------------------------------------------------

    \45\ See Appendix D, pages 65-69 for ADEQ's BART Analysis for 
PM10 at Apache Units 2 and 3. See AEPCO Apache Unit 2 
BART Analysis.
---------------------------------------------------------------------------

     Performance upgrades to existing hot-side ESP,
     Replacement of current ESP with a fabric filter, and
     Installation of a polishing fabric filter after ESP.

ADEQ found that all of these options are technically feasible and 
estimated their associated emission rates as shown in Table 9.

Table 9--Apache Units 2 and 3: Arizona's Controls and Emission Rates for
                                  PM10
------------------------------------------------------------------------
           Control technology              Expected PM10 emission rate
------------------------------------------------------------------------
ESP Upgrades...........................  0.03 lb/MMBtu.
Full Size Fabric Filter................  0.015 lb/MMBtu.
Polishing Fabric Filter................  0.015 lb/MMBtu.
------------------------------------------------------------------------

ADEQ found that a fabric filter, whether in addition to or as 
replacement for the ESP, would require additional energy, but did not 
identify any non-air environmental impacts from any of the three 
options. The cost of compliance and degree of visibility improvement 
for each of these options, as analyzed by ADEQ, are summarized in 
Tables 10 and 11.

                Table 10--Apache Unit 2: Arizona's Control Cost of Visibility Reduction for PM10
----------------------------------------------------------------------------------------------------------------
                                                                       Total         Cost per
                                                     Deciview       annualized       deciview      Average cost
                     Control                         reduction     cost (million      reduced         ($/ton)
                                                                        $)        (million $/dv)
----------------------------------------------------------------------------------------------------------------
ESP Upgrades....................................      Unknown         Unknown         Unknown         Unknown
Polishing Fabric Filter.........................           0.085          $2.217          $26.09          $9,121
Full Size Fabric Filter.........................           0.085           2.888           33.98          11,880
----------------------------------------------------------------------------------------------------------------


                Table 11--Apache Unit 3: Arizona's Control Cost of Visibility Reduction for PM10
----------------------------------------------------------------------------------------------------------------
                                                                       Total         Cost per
                                                     Deciview       annualized       deciview      Average cost
                     Control                         reduction     cost (million      reduced         ($/ton)
                                                                        $)        (million $/dv)
----------------------------------------------------------------------------------------------------------------
ESP Upgrades....................................      Unknown         Unknown         Unknown         Unknown
Polishing Fabric Filter.........................           0.094          $2.192          $23.32          $9,471
Full Size Fabric Filter.........................           0.094          $2.869          $30.52          12,390
----------------------------------------------------------------------------------------------------------------


[[Page 42847]]

     Based on its analysis of the five BART factors, as summarized 
above, ADEQ found BART for PM10 is upgrades to the existing 
ESP and a PM10 emissions limit of 0.03 lb/MMBtu for Units 2 
and 3. In particular, ADEQ referred to installation of a flue gas 
conditioning system, improvements to the scrubber bypass damper system, 
and implementation of programming optimization measures for ESP 
automatic voltage controls as potential upgrades. ADEQ also noted that 
``PM10 emissions will be measured by conducting EPA Method 
201/202 tests.''
    EPA's Evaluation: As noted above, AEPCO's and ADEQ's control cost 
calculations include costs that are disallowed by EPA's Control Cost 
Manual, such as owner's costs and AFUDC.\46\ In addition, AEPCO's and 
ADEQ's analyses do not demonstrate that all potential upgrades to the 
existing ESP were fully evaluated. Nonetheless, based on the small 
visibility improvement associated with PM10 reductions from 
these units (e.g., less than 0.1 dv improvement from the most stringent 
technology), we conclude that additional analyses of control options 
would not result in a different BART determination. As a result, we 
propose to approve ADEQ's PM10 BART determination at Apache 
Units 2 and 3.
---------------------------------------------------------------------------

    \46\ See AEPCO BART Analysis Technical Memorandum dated July 8, 
2009, page 12.
---------------------------------------------------------------------------

    Finally, we are seeking comment on whether test methods other than 
EPA Method 201 and 202 \47\ (chosen by ADEQ) should be allowed or 
required for establishing compliance with the PM10 limits 
that we are approving. In particular, as explained below, use of SCR 
\48\ at these units is expected to result in increased condensable 
particulate matter in the form of sulfuric acid mist 
(H2SO4). In effect, the emission limit would be 
more stringent than intended by ADEQ and would likely not be achievable 
in practice. In order to avoid this result, while still assuring proper 
operation of the particulate control devices, we are requesting on 
comment on whether to allow compliance with the PM10 limit 
to be demonstrated using test methods that do not capture condensable 
particulate matter, namely EPA Methods 1 through 4 and Method 5 or 
Method 5e.\49\ Method 201 is very rarely used for testing. The typical 
method used for filterable PM10 is Method 201A, ``constant 
sampling rate procedure,'' which is similar to Method 201, but is much 
more practical to perform on a stack.
---------------------------------------------------------------------------

    \47\ See 40 CFR part 51 Appendix M.
    \48\ EPA is proposing SCR as BART for all of the coal-fired 
units. See Section VII.
    \49\ See 40 CFR part 60 appendix A.
---------------------------------------------------------------------------

c. BART for SO2
    ADEQ's Analysis: Apache Units 2 and 3 currently have wet limestone 
scrubbers installed for SO2 removal.\50\ Under the BART 
Guidelines, a state is not required to evaluate the replacement of the 
current SO2 controls if their removal efficiency is over 50 
percent, but should consider cost-effective scrubber upgrades designed 
to improve the system's overall SO2 removal efficiency. 
Relying upon the BART analysis submitted by AEPCO,\51\ ADEQ found that 
the following potential upgrades to the scrubbers are technically 
feasible:
---------------------------------------------------------------------------

    \50\ See Arizona Regional Haze SIP, Appendix D, pages 69-71 for 
ADEQ's BART Analysis for SO2 at Apache Units 2 and 3.
    \51\ See AEPCO Apache Unit 2 BART Analysis.
---------------------------------------------------------------------------

     Elimination of bypass reheat,
     Installation of liquid distribution rings,
     Installation of perforated trays,
     Use of organic acid additives,
     Improved or upgraded scrubber auxiliary system equipment, 
and
     Redesigned spray header or nozzle.
    ADEQ found that any upgrades likely would not increase power 
consumption, but would increase scrubber waste disposal and makeup 
water requirements, and would reduce the stack gas temperature. These 
three factors are the normal outcome of treating more of the exhaust 
gas and removing more of the SO2 (increased scrubber waste 
disposal) and should not be given much weight in selecting a BART 
emission limit. ADEQ also noted that AEPCO had already made the 
following upgrades to the scrubbers: Elimination of flue gas bypass; 
splitting the limestone feed to the absorber feed tank and tower sump; 
upgrade of the mist eliminator system; installation of suction screens 
at pump intakes; automation of pump drain valves, and replacement of 
scrubber packing with perforated stainless steel trays. In addition, 
AEPCO tried using dibasic acid additive, but found that it did not 
result in significantly higher SO2 removal. ADEQ did not 
evaluate the cost or visibility impacts of any additional upgrades to 
the scrubbers, but determined that BART for SO2 emissions 
was no new controls and an emission limit of 0.15 lb/MMBtu on a 30-day 
rolling average basis.
    EPA's Evaluation: We are proposing to approve ADEQ's SO2 
BART determination for Apache Units 2 and 3. Although ADEQ has not 
demonstrated that it fully considered all cost effective scrubber 
upgrades, as recommended by the BART Guidelines, ADEQ conducted a five-
factor BART analysis and its final SO2 BART determination 
for Apache Units 2 and 3 is consistent with the presumptive BART limit 
of 0.15 lb/MMBtu for utility boilers.\52\ We have no evidence that 
additional analysis would have resulted in a lower emission limit. 
Therefore, we are proposing to approve the SO2 emission 
limit of 0.15 lb/MMBtu (30-day rolling average) for Apache Units 2 and 
3.
---------------------------------------------------------------------------

    \52\ See BART Guidelines Sec.  IV.E.4.
---------------------------------------------------------------------------

    However, we note that Apache can receive coal from a number of 
different mines that can have differing sulfur content and potential 
for SO2 emissions.\53\ Therefore, we are seeking comment on 
whether additional cost-effective scrubber upgrades are available that 
would warrant a lower emission limit. We are also requesting comment on 
whether requiring 90 percent control efficiency in addition to the lb/
MMBtu limit would better assure proper operation of the upgraded 
scrubbers when burning some types of low-sulfur western coal. If we 
receive information establishing that a lower limit is achievable or 
that a control efficiency requirement is needed, then we may disapprove 
the SO2 emissions limit set by ADEQ and promulgate a revised 
limit for one or both of these units.
---------------------------------------------------------------------------

    \53\ See, e.g. Apache Unit 2 BART Analysis, Table 3-1.
---------------------------------------------------------------------------

3. Cholla Units 2, 3 and 4
    Cholla Power Plant consists of four primarily coal-fired 
electricity generating units with a total plant-wide generating 
capacity of 1,150 megawatts. Unit 1 is a 125 MW tangentially-fired, 
dry-bottom boiler that is not BART-eligible. Units 2, 3 and 4 have 
capacities of 300 MW, 300 MW and 425 MW, respectively, and are 
tangentially-fired, dry-bottom boilers that are each BART-eligible. 
Based on information provided by APS, the Cholla units operate on a 
blend of bituminous and sub-bituminous rank coals from the Lee Ranch 
and El Segundo mines.\54\
---------------------------------------------------------------------------

    \54\ A copy of the coal contract, including obligation amounts 
and coal quality, can be found in Docket Item B-09, ``Additional APS 
Cholla BART response'', Appendix B.
---------------------------------------------------------------------------

a. BART for NOX
    ADEQ's Analysis: APS submitted a BART analysis to ADEQ in January 
2008. At the time of submittal, Cholla Units 2, 3 and 4 were equipped 
with close-coupled overfire air (COFA) as NOX controls. APS 
developed baseline NOX emissions by examining the highest 
24-hour average emissions from

[[Page 42848]]

2001 to 2003.\55\ APS examined several NOX control 
technologies, including combustion controls and add-on post combustion 
controls. A summary of the costs of compliance and visibility impacts 
associated with these options is presented in Table 12.
---------------------------------------------------------------------------

    \55\ See Docket Item B-06 through -08, APS Cholla BART Analyses, 
page 2-2.

                                    Table 12--Cholla Units 2, 3, and 4: Arizona's Cost and Visibility Summary for NOX
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Cost-effectiveness ($/   Visibility improvement
                                                                                                    ton)               \a\ (deciviews)        Cost per
                                                     Emission    Emissions   Annualized  --------------------------------------------------     total
                  Control option                     rate (lb/    removed     cost ($/                Incremental     Total    Incremental    deciview
                                                      MMBtu)     (tons/yr)      year)       Average      (from        (from       (from      improvement
                                                                                                       previous)    baseline)   previous)      ($/dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)...................................        0.50  ..........  ............  ..........  ...........  ..........  ...........  ............
LNB + SOFA........................................        0.22       3,314      $635,000        $192  ...........       0.187  ...........    $3,400,000
SNCR + LNB + SOFA.................................        0.17       3,900     2,175,000         558        2,628       0.218        0.031     9,980,000
ROFA..............................................        0.16       4,017     2,297,000         572        1,043       0.232        0.014     9,900,000
ROFA w/Rotamix....................................        0.12       4,485     3,384,000         755        2,323       0.261        0.029    12,970,000
SCR + LNB + SOFA..................................        0.07       5,071     9,625,000       1,898       10,650       0.287        0.026    33,540,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)...................................        0.41  ..........  ............  ..........  ...........  ..........  ...........  ............
LNB + SOFA........................................        0.22       2,096       635,000         303  ...........        0.13  ...........     5,040,000
SNCR + LNB + SOFA.................................        0.17       2,648     2,157,000         815        2,757        0.16        0.038    13,150,000
ROFA..............................................        0.16       2,758     2,243,000         813          782        0.17        0.005    13,270,000
ROFA w/Rotamix....................................        0.12       3,200     3,308,000       1,034        2,410        0.20        0.029    16,710,000
SCR + LNB + SOFA..................................        0.07       3,751     9,569,000       2,551       11,363        0.23        0.032    41,610,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
COFA (baseline)...................................        0.42  ..........  ............  ..........  ...........  ..........  ...........  ............
LNB + SOFA........................................        0.22       3,390       820,000         242  ...........        0.21  ...........     3,960,000
SNCR + LNB + SOFA.................................        0.17       4,259     2,852,000         670        2,338        0.27        0.058    10,760,000
ROFA..............................................        0.16       4,433     3,179,000         717        1,879        0.28        0.016    11,310,000
ROFA w/Rotamix....................................        0.12       5,129     4,537,000         885        1,951        0.34        0.055    13,500,000
SCR + LNB + SOFA..................................        0.07       5,998    13,230,000       2,206       10,003        0.41        0.072    32,430,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ At the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park.

    This information is contained in the Cholla BART analyses for each 
unit, and was relied upon by ADEQ in developing its RH SIP.\56\ 
Estimates of control technology emission rates were developed based on 
a combination of vendor quotes, contractor information, and internal 
APS information regarding environmental upgrades.\57\ Annual emission 
reductions were calculated based upon the emission rate estimates 
combined with annual capacity factors as reported in CAMD data from 
2001 to 2006.\58\ Control costs were also developed based on a 
combination of vendor quotes and contractor information. These cost 
calculations provided line item summaries of capital costs and annual 
operating costs, but did not provide further supporting information 
such as detailed equipment lists, vendor quotes, or the design basis 
for line item costs.
---------------------------------------------------------------------------

    \56\ See Docket Item B-06 through -08, APS Cholla BART Analyses. 
This information is also summarized in Docket Item B-01, Arizona 
Regional Haze SIP, Appendix D, Tables 11.3 through 11.5.
    \57\ As described in Table 3-2, Docket Items B-06 through -08, 
APS Cholla BART Analyses.
    \58\ As listed in Table 2-1, Docket Items B-06 through -08. 
Annual capacity factors used for each unit are 91 percent (Cholla 
2), 86 percent (Cholla 3), and 93 percent (Cholla 4).
---------------------------------------------------------------------------

    As part of its BART analysis, APS performed visibility modeling in 
order to evaluate the visibility improvement attributable to each of 
the NOX control technologies that it considered. This 
visibility modeling was performed using three years of meteorological 
data (2001 to 2003), and was generally performed in accordance with the 
WRAP protocol, with a few exceptions. For example, rather than using a 
constant monthly ammonia background concentration of 1.0 ppb as 
specified in the WRAP protocol, APS used a variable monthly background 
ammonia concentration that varied from 0.2 ppb to 1.0 ppb.
    For assessing the degree of visibility improvement, ADEQ considered 
only the visibility benefits at the area with the highest base case 
(pre-control) impact, the Petrified Forest National Park. For each 
control, ADEQ listed visibility improvement in deciviews, and 
visibility cost-effectiveness, (Arizona SIP submittal, ``Appendix D: 
Arizona BART--Supplemental Information'', p.77) as in the comparable 
section for Apache. For Unit 2, improvements range from 0.19 dv for LNB 
with SOFA to 0.29 dv for SCR. Costs per deciview range from $3.4 
million for LNB to $33.5 million for SCR. Benefits for Unit 3 are about 
20 percent lower (0.13 to 0.23 deciview), and for Unit 4 are about 20 
percent higher (0.21 to 0.41 deciview), with percent differences 
increasing with more stringent control. For Unit 3, costs per deciview 
range from $5 million for LNB with SOFA to $41.6 million for SCR (about 
30 percent higher than for Unit 2). For Unit 4, costs range from $4 
million for LNB with SOFA to $32.4 million for SCR (about 20 percent 
higher except that SCR has a slightly lower cost per deciview).
    ADEQ concluded (ibid., p. 79) that LNBs with new SOFA systems 
represent BART for all three units, noting that for all scenarios the 
visibility benefits were less than 0.5 dv. ADEQ also stated that SCR, 
the most expensive option, provides only about 0.1 dv benefit more than 
LNB with SOFA, the least expensive option. This statement appears to 
apply only to Units 2 and 3; the comparable benefit for Unit 4 is 0.2 
dv.
    In evaluating APS' BART analysis, ADEQ requested supporting 
information explaining certain assumptions used in the economic 
analysis, baseline emissions, and control technology options. Based on 
this additional

[[Page 42849]]

information as well as APS' original BART analysis, ADEQ determined 
that LNB with SOFA is BART for NOX at Cholla Units 2, 3, and 
4. In making this determination, ADEQ relied almost exclusively on the 
degree of visibility improvement. ADEQ cited small visibility 
improvement on a per-unit basis, stating that ``the change in deciviews 
between the least expensive and most expensive NOX control 
technologies [..] is only 0.104 deciviews.'' \59\ ADEQ's determination 
suggests that total capital costs may have been a consideration, 
although it is not clear to what extent this may have informed ADEQ's 
decision making, with the RH SIP simply stating, ``[t]he corresponding 
capital costs are $5.4 million for LNB/SOFA and $82.8 million for SCR 
with LNB/SOFA.'' \60\
---------------------------------------------------------------------------

    \59\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D, 
Page 79.
    \60\ Id.
---------------------------------------------------------------------------

    EPA's Evaluation: We disagree with several aspects of the analyses 
performed for Cholla Units 2, 3, and 4. Regarding the control cost 
calculations, we note that certain line item costs not allowed by the 
EPA Control Cost Manual were included, such as owner's costs, 
surcharge, and AFUDC. Inclusion of these line items has the effect of 
inflating the total cost of compliance and the cost per ton of 
pollutant reduced. As a result, we are proposing to find that ADEQ did 
not follow the requirements of section 51.308(e)(1)(ii)(A) by not 
properly considering the costs of compliance for each control option.
    Regarding ADEQ's analysis of visibility impacts, the modeling 
procedures relied on by ADEQ for assessing the visibility impacts from 
Cholla were generally in accord with EPA guidance, but the use of the 
modeling results in evaluating the BART visibility factor was 
problematic. As was the case for Apache, ADEQ appears to have 
considered benefits from controls on only one emitting unit at a time. 
EPA believes that ADEQ's use of this procedure substantially 
underestimates the degree of visibility improvement from controls. ADEQ 
also overlooked comparable benefits at seven Class I areas besides 
Petrified Forest, thereby understating the full visibility benefits of 
the candidate controls. Using the default 1 ppb ammonia background 
concentration would also have increased estimated impacts and control 
benefits. For these reasons, EPA proposes to find that the ADEQ 
selection of LNB for Cholla under the degree of visibility improvement 
BART factor is not adequately supported, and that more stringent 
control may be warranted.
b. BART for PM10
    ADEQ's Analysis: As of May 2009, Cholla Units 3 and 4 were both 
equipped with fabric filters for PM10 control, while Cholla 
Unit 2 was equipped with a mechanical dust collector and a venturi 
scrubber.\61\ In its BART analysis, ADEQ noted that the facility had 
committed to install a fabric filter at Unit 2 by 2015. Because fabric 
filters are the most stringent control available for reducing 
PM10 emissions, ADEQ did not conduct a full BART analysis, 
but concluded that fabric filters and an emission limit of 0.015 lb/
MMBtu are BART for control of PM10 at Units 2, 3, and 4. 
ADEQ also noted that ``PM10 emissions will be measured by 
conducting EPA Method 201/202 tests.''
---------------------------------------------------------------------------

    \61\ See Arizona Regional Haze SIP, Appendix D, pages 79-81 for 
ADEQ's BART Analysis for PM10 at Cholla Units 2, 3, and 
4.
---------------------------------------------------------------------------

    EPA's Evaluation: Given that ADEQ has chosen the most stringent 
control technology available and set an emissions limit consistent with 
other units employing this technology, we are proposing to approve this 
BART determination of an emission limit of 0.015 lb/MMBtu for 
PM10 at Cholla Units 2, 3, and 4.
c. BART for SO2
    Cholla Units 2, 3, and 4 are all equipped with wet lime scrubbers 
for SO2 control.\62\ Specifically, Unit 2 is equipped with 
four venturi flooded disc scrubbers/absorber with lime reagent, capable 
of achieving 0.14 lb/MMBtu to 0.25 lb/MMBtu of SO2. Units 3 
and 4 were retrofitted in 2009 and 2008, respectively, with scrubbers 
capable of achieving 0.15 lb/MMBtu of SO2.
---------------------------------------------------------------------------

    \62\ See Arizona Regional Haze SIP, Appendix D, pp. 81-83, for 
ADEQ's BART Analysis for SO2 at Cholla Units 2, 3, and 4.
---------------------------------------------------------------------------

    ADEQ's Analysis: Based on a limited five-factor analysis, ADEQ 
determined BART for SO2 at Cholla Unit 2 is upgrades to the 
existing scrubber that would achieve a limit of 0.15 lb/MMBtu. Because 
the BART analysis submitted by APS was conducted prior to installation 
of the scrubbers on Units 3 and 4, it included an analysis of other 
potential control technologies, namely, dry flue gas desulfurization 
and dry sodium sorbent injection. However, APS had already installed 
the wet lime scrubbers by the time ADEQ conducted its own BART 
analysis. Therefore, ADEQ did not consider SO2 controls 
other than wet lime scrubbers for Units 3 and 4, but determined BART as 
use of these scrubbers with an associated emission limit of 0.15 lb/
MMBtu of SO2.
    EPA's Evaluation: We are proposing to approve ADEQ's BART 
determination for SO2 at Cholla Units 2, 3, and 4. Although 
ADEQ did not fully consider all cost-effective scrubber upgrades as 
recommended by the BART Guidelines, we have no basis for concluding 
that additional analysis would have resulted in a lower emission limit. 
Therefore, we are proposing to approve the SO2 emission 
limit of 0.15 lb/MMBtu (30-day rolling average) for Cholla Units 2, 3, 
and 4. However, we are seeking comment on whether additional cost-
effective scrubber upgrades are available that would warrant a lower 
emission limit. If we receive comments establishing that a lower limit 
is achievable, then we may disapprove the SO2 emissions 
limit set by ADEQ and promulgate a revised limit for one or more of 
these units.
 4. Coronado Units 1 and 2
    Coronado Generating Station consists of two EGUs with a total 
plant-wide generating capacity of over 800 MW. Units 1 and 2 are both 
dry-bottom, turbo-fired boilers, each with a gross unit output of 411 
MW. Both units are BART-eligible and are coal-fired boilers operating 
on primarily Powder River Basin sub-bituminous coal.
    SRP entered into a consent decree with EPA in 2008.\63\ This 
consent decree resolved alleged violations of the CAA which occurred at 
Units 1 and 2 of the Coronado Generating Station, arising from the 
construction of modifications without obtaining appropriate permits 
under the Prevention of Significant Deterioration provisions of the 
CAA, and without installing and applying best available control 
technology. The consent decree resolved the claims alleged by EPA in 
exchange for SRP's payment of a civil penalty and SRP's commitment to 
perform injunctive relief including: (1) Installation of pollution 
control technology to control emissions of NOX, 
SO2, and PM--including flue gas desulfurization devices to 
control SO2 on Units 1 and 2 at the Coronado Station and 
installation of SCR to control NOX on one of the units (Unit 
2); (2) meet specified emission rates or removal efficiencies for 
NOX, SO2, and PM; (3) comply with a plant-wide 
emissions cap for NOX; and (4) perform $ 4 million worth of 
mitigation projects. The consent decree is not a permit, and compliance 
with the consent decree does not guarantee compliance with all 
applicable federal, state, or local laws or regulations. The emission 
rates and

[[Page 42850]]

removal efficiencies set forth in the consent decree do not relieve SRP 
from any obligation to comply with other state and federal requirements 
under the CAA, including SRP's obligation to satisfy any State modeling 
requirements set forth in the Arizona SIP.
---------------------------------------------------------------------------

    \63\ See Docket Item G-01, Consent Decree between United States 
and Salt River Project Agricultural Improvement and Power District.
---------------------------------------------------------------------------

a. BART for NOX
    ADEQ's Analysis: ADEQ's BART analysis relied in large part on an 
analysis submitted by SRP in February 2008. In its analysis, SRP 
developed baseline NOX emissions by examining continuous 
emission monitoring system (CEMS) data from 2001 to 2003.\64\ SRP 
examined several NOX control technologies, including 
combustion controls and add-on post combustion controls. A summary of 
the costs of compliance and visibility impacts associated with these 
options is presented in Table 13. This information was contained in the 
SRP Coronado BART analysis, and was relied on by ADEQ in developing its 
RH SIP. Estimates of control technology emission rates were developed 
based on information provided by equipment vendors.\65\ SRP's analysis 
did not provide an estimate of annual emissions.
---------------------------------------------------------------------------

    \64\ See Docket Item B-10, SRP Coronado BART Analysis, page 3-1.
    \65\ See Docket Item B-10, SRP Coronado BART Analysis, p. 4-5.

                                                         Table 13--Coronado Units 1 and 2: Arizona's Cost and Visibility Summary for NOX
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Emission rate  (lb/                           Cost-effectiveness \b\        Visibility                         Improvement in
                                                                     MMBtu)                                          ($/ton)             improvement \c\                   visibility index \e\
                                                            ------------------------   Total       Total    ------------------------       (deciviews)         Cost per         (deciviews)
                                                                                     emissions   annualized                         ------------------------    total    -----------------------
                       Control option                                                 removed     cost ($/              Incremental                            deciview     Total
                                                               Unit 1      Unit 2    \a\ (tons/    year)      Average      (from       Total    Incremental  improvement    (from    Incremental
                                                                                        yr)                              previous)     (from       (from      \d\ ($/dv)     base       (from
                                                                                                                                     baseline)   previous)                  case)     previous)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline).............................................       0.433       0.466  .........  ...........  .........  ...........  .........  ...........  ...........  .........  ...........
Full LNB + OFA.............................................       0.32        0.32       5,838   $1,227,000       $210  ...........       0.12  ...........  $10,225,000       0.11  ...........
Full SNCR + LNB + OFA......................................       0.22        0.22      10,195    4,654,000        456         787        0.16        0.04    29,087,500       0.19       0.080
Partial SCR + LNB + OFA \f\................................       0.32        0.08      11,003    8,557,000        778       4,830        0.24        0.12    35,654,167       0.22       0.030
Full SCR + LNB + SOFA......................................       0.08        0.08      16,730   17,090,000      1,022       1,490        0.39        0.27    43,820,513       0.34       0.120
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ SRP did not provide estimates of annual emissions in its BART analysis. These values are summarized from the Arizona RH SIP.
\b\ Cost-effectiveness was not presented in the Arizona RH SIP. These values are calculated from the emission removal and annualized costs that were included in the RH SIP.
\c\ Visibility improvement at the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park, from the SRP Coronado BART Analysis.
\d\ Cost per total deciview improvement was not presented in the Arizona RH SIP. These values are calculated from the annualized costs that were included in the RH SIP, and the visibility
  improvement at Petrified Forest National Park, from the SRP Coronado BART Analysis.
\e\ Visibility index used in the Arizona RH SIP is the average of the impacts over the nine closest Class I areas.
\f\ This control option examined LNB+OFA on Unit 1 and SCR on Unit 2.

    Control costs for the various options considered were developed by 
Sargent and Lundy, the engineering firm retained by SRP for emission 
control projects at Coronado. In its BART analysis and subsequent 
additional response to ADEQ, SRP provided summaries of total control 
costs, such as total annual operating and maintenance costs and total 
annualized capital cost, but did not provide cost information at a 
level of detail that included line item costs. \66\
---------------------------------------------------------------------------

    \66\ See Docket Item B-11, Additional SRP Coronado response.
---------------------------------------------------------------------------

    As part of its BART analysis, SRP performed visibility modeling in 
order to evaluate the visibility improvement attributable to each of 
the NOX control technologies that it considered. This 
visibility modeling was performed using three years of meteorological 
data (2001 to 2003), and relied partially on the WRAP protocol with 
certain revisions based on EPA and Federal Land Manager guidance that 
became available in the intervening period. For example, the WRAP 
protocol used CALPUFF model version 6, whereas SRP used the current 
EPA-approved CALPUFF version 5.8.
    For assessing the degree of visibility improvement, ADEQ considered 
a visibility index, defined as the average of the visibility benefits 
at the closest nine Class I areas. The average included the five areas 
with the highest baseline impacts. This metric is unlike that used for 
Apache and Cholla, for which the benefits at the single area with 
maximum baseline impact were used. Since it is an average, it is 
somewhat similar to the sum of benefits over the nine areas, a 
cumulative metric used in other analyses, except it is divided by nine 
to compute the average. (Typically the sum would be computed over all 
17 Class I areas impacted by the Coronado facility.) For each control, 
ADEQ listed the average visibility improvement in deciviews, and cost 
in millions of dollars per average deciview improvement.\67\ 
Improvements in the visibility index ranged from 0.11 dv for LNB with 
OFA to 0.34 dv for SCR. Costs per deciview for the index ranged from 
$11.1 million for LNB to $50.3 million for SCR (not shown in the Table 
above).
---------------------------------------------------------------------------

    \67\ Arizona RH SIP, Appendix D, p. 112.
---------------------------------------------------------------------------

    While an average of the visibility benefits over the nearest areas 
is an informative number, it is not directly comparable to the more 
typical metrics of the maximum benefit seen at any area, and sum over 
the areas. Moreover, neither the ADEQ RH SIP nor the facility's report 
(BART Analysis for the Coronado Generating Station Units 1 & 2, 
Document No. 05830-012-200, ENSR Corporation, February 2008) include 
control benefits for individual Class I areas. Thus, the maximum area 
benefit cannot be read from either document. However, the benefits can 
be computed from the individual area impacts that are provided in SRP's 
report, including for Petrified Forest National Park, which had the 
highest baseline impact. Figures that are comparable to those for 
Apache and Cholla are included in the Table 13. Coronado's maximum area 
visibility benefits range from 0.12 dv for LNB to 0.39 dv for SCR. The 
costs per deciview range from $10.2 million for LNB with OFA to $43.8 
for SCR.
    In evaluating SRP's BART analysis, ADEQ requested additional 
supporting information from SRP regarding control cost calculations, 
and for further explanation regarding SRP's recommendation for BART for 
NOX. In developing its Regional Haze SIP, ADEQ

[[Page 42851]]

determined that LNB with OFA constitutes BART for NOX at 
Coronado Units 1 and 2. In making this determination, ADEQ did not 
provide adequate information regarding its rationale or weighing of the 
five factors, stating only ``[a]fter reviewing the BART analysis 
provided by the company, and based upon the information above, ADEQ has 
determined that BART for NOX at Coronado Units 1 and 2 is 
advanced combustion controls (Low NOX burners with OFA) with 
an associated NOX emission rate of 0.32 lb/MMBtu [..]'' \68\
---------------------------------------------------------------------------

    \68\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D, 
Page 112.
---------------------------------------------------------------------------

    EPA's Evaluation: We disagree with several aspects of the BART 
analysis for Coronado Units 1 and 2. Regarding the control cost 
calculations, we note that SRP did not provide ADEQ with control cost 
calculations at a level of detail that allowed for a comprehensive 
review. Without such a level of review, we do not believe that ADEQ was 
able to evaluate whether SRP's control costs were reasonable. As a 
result, we are proposing to find that ADEQ did not follow the 
requirements of section 51.308(e)(1)(ii)(A) because ADEQ did not 
properly consider the costs of compliance for each control option.
    The modeling procedures relied on by ADEQ for assessing the 
visibility impacts from Coronado were generally in accord with EPA 
guidance. Coronado Units 1 and 2 were modeled together, and the 
modeling was done with the current regulatory version 5.8 of the 
CALPUFF modeling system.\69\ However, the use of the modeling results 
in evaluating the BART visibility factor was problematic. The modeling 
results show that, of the controls considered, only SCR would provide 
substantial visibility benefits; the other controls options would 
provide roughly half the 0.5 dv contribution benchmark. ADEQ did not 
consider the typical visibility metrics of benefit at the area with 
maximum impact, nor benefits summed over the areas. Using the default 1 
ppb ammonia background concentration would also have increased 
estimated impacts and control benefits. For these reasons, EPA proposes 
to find that the ADEQ selection of LNB with OFA for Coronado under the 
degree of visibility improvement BART factor is not adequately 
supported, and that more stringent control may be warranted. ADEQ 
provided little reasoning about the visibility basis for the Coronado 
BART selection. For example, there is no weighing of the visibility 
benefits and visibility cost-effectiveness for the various candidate 
controls and the various Class I areas.
---------------------------------------------------------------------------

    \69\ Arizona Regional Haze SIP, Appendix D, p. 112.
---------------------------------------------------------------------------

    In addition to the problems noted above, we find that overall ADEQ 
has not documented its evaluation of the results of its five-factor 
analysis, as required by 51.308(e)(1)(ii)(A) and the BART Guidelines. 
Although ADEQ has developed information regarding each of the five 
factors, its selection of BART does not cite or interpret information 
from its analyses. ADEQ does not, for example, indicate whether or not 
it considered any cost thresholds to be reasonable or expensive in 
analyzing the costs of compliance for the various control options. We 
note that ADEQ has made similar NOX BART determinations of 
LNB with OFA at other facilities, such as Cholla Power Plant. Although 
ADEQ's BART determinations for these other facilities implied that cost 
of compliance was an important consideration, it does not provide a 
rationale for the determination of NOX BART at Coronado.\70\ 
Therefore, we propose to determine that ADEQ did not follow the 
requirements of section 51.308(e)(1)(ii)(A). We propose to disapprove 
ADEQ's selection of LNB with OFA as BART for NOX at Coronado 
Units 1 and 2.
---------------------------------------------------------------------------

    \70\ We do note, however, that SRP does provide some additional 
analysis on this position in the BART analysis it submitted to ADEQ 
and in the responses it provided to ADEQ's additional questions. 
Aside from stating that it reviewed SRP's analysis, ADEQ did not 
specifically reference or include any aspects of SRP's analysis in 
the RH SIP. As a result, we are not assuming that ADEQ necessarily 
agrees with SRP's rationale, and have therefore not provided an 
analysis of it.
---------------------------------------------------------------------------

b. BART for PM10
    Emissions of PM10 from Coronado Units 1 and 2 are 
currently controlled by hot-side ESPs.\71\ Under the terms of the 
Consent Decree described above in Section 4, SRP is required to 
optimize its ESPs to achieve a PM10 emission rate of 0.030 
lb/MMBtu.\72\
---------------------------------------------------------------------------

    \71\ See Arizona Regional Haze SIP, Appendix D, p. 112 for 
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2; 
and BART Analysis for Coronado Generating Station Units 1 and 2 
(February 2008) for SRP's analysis.
    \72\ Docket Item G-01, Consent Decree between United States and 
Salt River Project Agricultural Improvement and Power District, 
Sec.  V.
---------------------------------------------------------------------------

    ADEQ's Analysis: ADEQ conducted a streamlined PM10 BART 
analysis for Coronado Units 1 and 2. In particular, ADEQ found that 
``BART for similar emissions units with similar emissions controls was 
determined to be 0.03 lb/MMBtu.'' ADEQ concluded that because Coronado 
Units 1 and 2 are already meeting a limit of 0.03 lb/MMBtu, ``further 
analysis was determined to be unnecessary.''
    EPA's Evaluation: ADEQ's analysis does not demonstrate that all 
potential upgrades to the existing ESPs were fully evaluated. However, 
we have no evidence that additional reductions in PM10 
emissions would be achievable or cost-effective, or that such 
reductions would yield substantial visibility benefits. Therefore, we 
propose to approve ADEQ's PM10 BART determination at 
Coronado. However, we are seeking comment on whether additional cost-
effective upgrades to the existing ESPs are available that would 
warrant a lower emission limit. If we receive comments establishing 
that a lower limit is achievable, then we may disapprove the 
PM10 emissions limit set by ADEQ and promulgate a revised 
limit for one or both of these units.
    Finally, we are seeking comment on whether test methods other than 
EPA Method 201 and 202 \73\ (chosen by ADEQ) should be allowed or 
required for establishing compliance with the PM10 limits 
that we are approving. In particular, as explained below, use of SCR at 
these units is expected to result in increased condensable particulate 
matter in the form of H2SO4. In effect, the 
emission limit would be more stringent than intended by ADEQ and would 
likely not be achievable in practice. In order to avoid this result, 
while still assuring proper operation of the particulate control 
devices, we are requesting on comment on whether to allow compliance 
with the PM10 limit to be demonstrated using test methods 
that do not capture condensable particulate matter, namely EPA Methods 
1 through 4 and Method 5 or Method 5e.\74\ Method 201 is very rarely 
used for testing. The typical method used for filterable 
PM10 is Method 201A, ``constant sampling rate procedure,'' 
which is similar to Method 201, but is much more practical to perform 
on a stack.
---------------------------------------------------------------------------

    \73\ See 40 CFR part 51 appendix M.
    \74\ See 40 CFR part 60 appendix A.
---------------------------------------------------------------------------

c. BART for SO2
    Emissions of SO2 at Coronado Units 1 and 2 are currently 
controlled with the use of low-sulfur coal and partial wet flue 
gas.\75\ However, the consent decree between EPA and SRP described 
above requires installation of wet flue gas desulfurization (WFGD) 
systems at either Unit 1 or Unit 2 by January 2012, and at the 
remaining unit by January 1, 2013. Both units must achieve and maintain 
a 30-day rolling average SO2 removal efficiency of at least 
95.0

[[Page 42852]]

percent or a 30-day rolling average SO2 emissions rate of no 
greater than 0.080 lb/MMBtu.
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    \75\ See Arizona Regional Haze SIP, Appendix D, pp. 113-15 for 
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2; 
and Docket No. B.10, BART Analysis for Coronado Generating Station 
Units 1 and 2 (Feb. 2008) for SRP's analysis.
---------------------------------------------------------------------------

    ADEQ's Analysis: Because WFGD is the most effective control 
technology available for controlling SO2 emissions, ADEQ did 
not evaluate other control options. Table 14 summarizes Arizona's the 
costs of compliance and improvement in visibility expected to result 
from installation of WFGD at both units. Based on this information, 
ADEQ determined SO2 BART for both units is the installation 
of WFGDs and an emission rate of 0.08 lbs/MMBtu on 30-day rolling 
average basis.

    Table 14--Coronado Units 1 and 2: Arizona's Bart Summary for SO2
------------------------------------------------------------------------
                                  Option 1, baseline    Option 2, WFGD
------------------------------------------------------------------------
Reduction in Emission (tpy).....  ..................              25,753
Annualized Cost.................  ..................         $44,353,330
Visibility Index (dv)...........                2.66                1.28
Improvement in Visibility Index   ..................                1.38
 (dv)...........................
Incremental Cost-effectiveness    ..................         $32,140,094
 ($ per dv).....................
------------------------------------------------------------------------

    EPA's Evaluation: We are proposing to approve ADEQ's SO2 
BART determination for Coronado Units 1 and 2. Although we do not 
necessarily agree with the underlying cost and visibility analyses 
performed by SRP, we have no evidence that additional analysis would 
have resulted in a lower emission limit. Therefore, we propose to 
approve ADEQ's SO2 emission limit of 0.08 lb/MMBtu (30-day 
rolling average) for Coronado Units 1 and 2. However, we are seeking 
comment on whether a lower emission limit may be achievable when the 
units are burning a lower-sulfur coal. If we receive comments 
establishing that a lower limit is achievable, then we may disapprove 
the SO2 emissions limit set by ADEQ and promulgate a revised 
limit for one or both of these units.

 D. Enforceability of BART Limits

    Regional Haze SIPs must include requirements to ensure that BART 
emission limits are enforceable. In particular, the RHR requires 
inclusion of (1) A schedule for compliance with BART for each source 
subject to BART; (2) a requirement for each BART source to maintain the 
relevant control equipment; and (3) procedures to ensure control 
equipment is properly operated and maintained.\76\ General SIP 
requirements also mandate that the SIP include all regulatory 
requirements related to monitoring, recordkeeping and reporting for the 
BART emissions limitations.\77\ ADEQ did not include any of these 
elements in its Regional Haze SIP.\78\ Therefore, we are proposing to 
disapprove this aspect of the Regional Haze SIP for these three sources 
and to promulgate a FIP to ensure the emission limits are enforceable.
---------------------------------------------------------------------------

    \76\ 40 CFR 51.308(e)(1).
    \77\ See, e.g. CAA section 110(a)(2) (F) and 40 CFR 51.212(c).
    \78\ As described above, ADEQ did specify a test method for 
PM10 for each of the relevant sources (Method 201/202). 
However, we are proposing to also allow the use of test methods that 
do not capture condensable particulate matter, namely EPA Methods 1 
through 4 and Method 5 or Method 5e.
---------------------------------------------------------------------------

VII. EPA's Proposed FIP Actions

A. EPA's BART Analyses and Determinations

    EPA conducted a new five-factor BART analysis of the three 
facilities in order to evaluate Arizona's RH SIP, and to document the 
technical basis for proposing BART determinations in our FIP. Because 
EPA generally concurs with ADEQ's BART analyses in Steps 1 and 2 
(Identify All Available Retrofit Control Technologies and Eliminate 
Technically Infeasible Options), we focused our technical analysis on 
Steps 3, 4 and 5 (Evaluate Control Effectiveness of Remaining Control 
Technologies, Evaluate Impacts and Document Results, and Evaluate 
Visibility Impacts). We relied on contractor assistance from the 
University of North Carolina Institute for the Environment to evaluate 
control effectiveness, perform cost calculations, and conduct new 
visibility modeling for each of the units at the three facilities, 
except Apache Generating Station Unit 1 for which this level of 
analysis was unnecessary. Our approach to each of these factors is 
explained below, followed by our BART determinations for the three 
sources in the next section. Copies of the contractor's reports and the 
details of our BART analyses are in our Technical Support Document 
(TSD) available in the docket.
 1. Costs of Compliance
    Cost Estimates and Calculations: In estimating the costs of 
compliance, we have relied on facility data from a number of sources 
including ADEQ, the Energy Information Administration (EIA), and EPA's 
Control Cost Manual. As discussed previously, ADEQ, in developing its 
RH SIP, requested certain clarifying information from the facilities 
regarding their control cost calculations, including greater detail 
regarding the underlying assumptions. ADEQ received responses of 
varying detail to these requests. Although in some cases the facilities 
provided summaries of certain broad line item costs, in no case does 
the supporting information that is available provide detail at a level 
that allows for critical review. In the case of SRP Coronado Generating 
Station, ADEQ received only a broad summary of control costs without 
itemized breakdowns of specific costs.
    As a result, we have used EPA's Integrated Planning Model (IPM) to 
calculate the capital costs and annual operating costs associated with 
the various NOX control options. EPA's Clean Air Markets 
Division (CAMD) uses IPM to evaluate the cost and emissions impacts of 
proposed policies to limit emissions of SO2, NOX, 
carbon dioxide (CO2), and mercury (Hg) from the electric 
power sector. Developed by ICF Consulting, Inc. and used to support 
public and private sector clients, IPM is a multi-regional, dynamic, 
deterministic linear programming model of the U.S. electric power 
sector. EPA has used IPM in rulemakings such as the Mercury and Air 
Toxics Standard and the Cross-State Air Pollution Rule. For the 
purposes of this BART determination, we specifically used only the 
NOX emission control technology cost methodologies contained 
in EPA's IPM Base Case v4.10 (August 2010).\79\ For Base Case v4.10, 
EPA's Clean Air Markets Division contracted with engineering firm 
Sargent and Lundy to perform a complete bottom-up engineering 
reassessment of the cost and performance assumptions for SO2 
and nitrogen oxides NOX emission controls. Summaries of our 
control cost estimates for the various control technology options 
considered for each unit are included below. Detailed cost

[[Page 42853]]

calculations, including our contractor's report and cost calculation 
spreadsheets, are in the Technical Support Document.
---------------------------------------------------------------------------

    \79\ http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

    We used publicly available information to estimate that AEPCO is a 
small utility. EPA requested information from AEPCO on the economics of 
operating Apache Generating Station and what impact the installation of 
SCR may have on the economics of operating Apache Generating Station. 
Specifically, EPA is seeking information on the ability of AEPCO to 
recover the cost of pollution control technology through rate increases 
and the impact those rate increases may have on AEPCO's customers. If 
we receive comments sufficiently documenting that installation of SCR 
may have a severe impact on the economics of operating Apache 
Generating Station, we may incorporate such considerations in our 
selection of BART. Our impact analysis and request for comment is 
discussed in more detail below, under EPA's BART Determinations for 
Apache Units 2 and 3.
    Control Effectiveness: The evaluation of control effectiveness is 
an important part of a five-factor analysis because it influences both 
cost-effectiveness and visibility benefits. The BART Guidelines note 
that for each technically feasible control option:

    ``It is important * * * that in analyzing the technology you 
take into account the most stringent emission control level that the 
technology is capable of achieving. You should consider recent 
regulatory decisions and performance data (e.g., manufacturer's 
data, engineering estimates and the experience of other sources) 
when identifying an emissions performance level or levels to 
evaluate.'' \80\
---------------------------------------------------------------------------

    \80\ 40 CFR part 51, appendix Y Sec.  IV.D.3.

In general, our estimates of LNB and SNCR control effectiveness differ 
slightly from the control effectiveness levels considered by ADEQ. In 
the case of LNB, for example, this is the result of the fact that 
actual emissions data for LNB performance were available for certain 
units at the time of our analysis. ADEQ's analysis was performed at an 
earlier date when these emissions data were not available. More 
detailed information regarding these differences is in our discussion 
of individual facilities in the following sections of this notice, as 
well as in our TSD.
    In particular, we find that ADEQ did not adequately support its 
estimate of SCR control effectiveness. SCR, as an add-on control 
technology, can be installed by itself as a standalone option or in 
conjunction with burner upgrades. In cases where units can be upgraded 
with combustion control technology such as low-NOx burners, SCR is 
commonly installed as an add-on post-combustion control. When 
evaluating control options with a range of emission performance levels, 
the BART Guidelines indicate that ``in analyzing the technology you 
take into account the most stringent emission control level that the 
technology is capable of achieving.'' \81\ Existing vendor literature 
and technical studies indicate that SCR systems are capable of 
achieving a 0.05 lb/MMBtu emission rate (approximately 80-90% control 
efficiency) and that this emission rate can be achieved on a retrofit 
basis, particularly when combined with combustion control technology 
such as LNB.\82\
---------------------------------------------------------------------------

    \81\ 70 FR 39166.
    \82\ See Docket Items G-04, ``Emissions Control: Cost-Effective 
Layered Technology for Ultra-Low NOX Control'' (2007), 
Docket Item G-05 ``What's New in SCRs'' (2006), and Docket Item G-06 
``Nitrogen Oxides Emission Control Options for Coal-Fired Electric 
Utility Boilers'' (2005).
---------------------------------------------------------------------------

    For control options involving the installation SCR in conjunction 
with LNB, ADEQ considered the achievable emission rate to be between 
0.07 lb/MMbtu (for Apache and Cholla) and 0.08 lb/MMbtu (for Coronado). 
These emission rates are within a range of SCR performance that has 
been considered by other western states in preparing RH SIPs, and may 
possibly be an appropriate estimation of the site-specific level of SCR 
performance for coal-fired units at Apache, Cholla, and Coronado. We 
note that the BART Guidelines indicate that, ``In assessing the 
capability of the control alternative, latitude exists to consider 
special circumstances pertinent to the specific source under review [* 
* *]. However, you should explain the basis for choosing the alternate 
level (or range) of control in the BART analysis.'' \83\ Although the 
alternate levels of emission control considered by ADEQ for SCR in 
conjunction with LNB were stated in each respective facility's BART 
analysis, these emission rates were not further supported by any 
calculations, engineering analysis, or documentation. We do not believe 
that AEPCO, APS, and SRP have provided adequate supporting analysis to 
justify these emission rates. We are seeking comment on whether it is 
appropriate to consider an emission rate less stringent than 0.05 lb/
MMBtu when evaluating the installation SCR in conjunction with LNB at 
Apache, Cholla, and Coronado.
---------------------------------------------------------------------------

    \83\ 40 CFR part 51, appendix Y Sec.  IV.D.3.
---------------------------------------------------------------------------

    In the absence of source-specific considerations warranting a less 
stringent control level, we presume that an emissions limit of 0.05 lb/
MMBtu is achievable by these units through the use of SCR in addition 
to advanced combustion controls. We have recently received information 
from AEPCO and SRP regarding potential NOX controls at their 
facilities. This information arrived too late to be fully evaluated for 
this proposed rulemaking, and EPA will need additional documentation 
from the utilities to support the information that they have provided 
to date. We have put the utility information in the docket for public 
review, and we will evaluate the information, and any additional 
information that the utilities may want to provide prior to making our 
final BART determinations.\84\ If we receive additional comments that 
sufficiently document source-specific considerations justifying the use 
of an emission rate less stringent than 0.05 lb/MMBtu, we may 
incorporate such considerations in our selection of BART.
---------------------------------------------------------------------------

    \84\ Docket Items C-15 ``Letter from Kelly Barr (SRP) to Deborah 
Jordan (EPA)'' and C-16 ``Letter from Michelle Freeark (AEPCO) to 
Deborah Jordan (EPA).''
---------------------------------------------------------------------------

 2. Energy and Non-Air Environmental Impacts
    Energy Impacts: With respect to the potential energy impacts of the 
BART control options, we note that SCR incurs a draft loss that will 
increase parasitic loads, and that other emissions controls may also 
have modest energy impacts. The costs for direct energy impacts, i.e., 
power consumption from the control equipment and additional draft 
system fans from each control technology, are included in the cost 
analyses and are not considered further in this section. Indirect 
energy impacts, such as the energy to produce raw materials, are not 
considered, consistent with the BART guidelines.
    Ammonia Adsorption: Ammonia adsorption (resulting from ammonia 
injection from SCR or selective non-catalytic reduction--SNCR) to fly 
ash is generally not desirable due to odor but does not impact the 
integrity of the use of fly ash in concrete. However, other 
NOX control technologies, including LNB, also have 
undesirable impacts on fly ash. LNBs increase the amount of unburned 
carbon in the fly ash, also known as Loss of Ignition (LOI), which does 
affect the integrity of the concrete. Commercial scale technologies 
exist to remove ammonia and LOI from fly ash. Moreover, the impact of 
SCR on fly ash is smaller than the impact of LNB on fly ash, and in 
both cases, the adverse effects can be mitigated.\85\ We conclude

[[Page 42854]]

that the ability of the relevant facilities to sell fly ash is unlikely 
to be affected by the installation of SCR and SNCR technologies.
---------------------------------------------------------------------------

    \85\ ``Impact of Ammonia in Fly Ash on its Beneficial Use,'' 
Memorandum from Nancy Jones and Stephen Edgerton, EC/R Incorporated, 
to Anita Lee, U.S. EPA/Region 9, August 31, 2010. Also see the TSD 
for further discussion.
---------------------------------------------------------------------------

    Safety: SCR and SNCR may involve potential safety hazards 
associated with the transportation and handling of anhydrous ammonia. 
Since each of the relevant facilities is served by a nearby railroad 
line, EPA concludes that the use of ammonia does not pose any 
additional safety concern as long as established safety procedures are 
followed.
    Thus, EPA proposes to find that potential energy and non-air 
quality impacts do not warrant elimination of any of the otherwise 
feasible control options for NOX at any of the sources.
3. Pollution Control Equipment in Use at the Source
    The presence of existing pollution control technology at each 
source is reflected in our BART analysis in two ways: First, in the 
consideration of available control technologies, and second, in the 
development of baseline emission rates for use in cost calculations and 
visibility modeling. As noted above, we largely agree with ADEQ's 
consideration of available control technologies. However, because 
several of the affected units have had new controls installed in the 
last several years, we have adjusted the baseline emissions periods to 
reflect current control technology at the sources, as described further 
below in our proposed BART determinations.
 4. Remaining Useful Life of the Source
    We are considering each source's ``remaining useful life'' as one 
element of the overall cost analysis as allowed by the BART Guidelines. 
Since we are not aware of any federally- or State-enforceable shut-down 
date for any of the affected sources, we have used the default 20-year 
amortization period in the EPA Cost Control Manual as the remaining 
useful life of the facilities considered in this proposed action.
 5. Degree of Improvement in Visibility
    EPA estimated the degree of visibility improvement expected from a 
BART control based on the difference between baseline visibility 
impacts prior to controls and visibility impacts with controls in 
operation. EPA used the CALPUFF model version 5.8 \86\ to determine the 
baseline and post-control visibility impacts for all three facilities. 
EPA followed the modeling approach recommended in the BART Guidelines. 
We developed a modeling protocol, used maximum daily emissions as a 
baseline, applied estimated percent reductions for alternative control 
technologies, and used the CALPUFF model to estimate visibility impacts 
at Class I areas within 300 kilometers.
---------------------------------------------------------------------------

    \86\ EPA relied on version 5.8 of CALPUFF because it is the EPA-
approved version promulgated in the Guideline on Air Quality Models 
(40 CFR part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 
2003. It was also the approved version when EPA promulgated the BART 
Guidelines (70 FR 39122, July 6, 2005). EPA updated the specific 
version to be used for regulatory purposes on June 29, 2007, 
including minor revisions as of that date; the approved CALPUFF 
modeling system includes CALPUFF version 5.8, level 070623, and 
CALMET version 5.8 level 070623. At this time, any other version of 
the CALPUFF modeling system would be considered an ``alternative 
model'', subject to the provisions of Guideline on Air Quality 
Models section 3.2.2(b), requiring a full theoretical and 
performance evaluation.
---------------------------------------------------------------------------

a. Modeling Protocol
    A modeling protocol was developed by our contractor \87\ at the 
University of North Carolina that is based largely on the WRAP 
protocol,\88\ although there are a few differences between our protocol 
and that of the WRAP. Both protocols used meteorological inputs for 
2001, 2002, and 2003 based on the Mesoscale Model version 5 (MM5). EPA 
meteorological inputs differed from the WRAP's in that the WRAP 
incorporated upper air data, as recommended by the Federal Land 
Managers, and also values for some parameters that enabled smoother and 
more realistic wind fields. These CALMET inputs were developed by the 
ENSR corporation for modeling of emissions at the Navajo Generating 
Station.\89\ Another key difference was EPA's use of the current 
regulatory version of the CALPUFF modeling system, version 5.8. 
Facility stack parameters, such as stack height and exit temperature, 
were generally the same as those provided by WRAP member states to the 
WRAP, except that in some cases updated parameters were provided by the 
facilities at EPA's request.
---------------------------------------------------------------------------

    \87\ Technical Analysis for Arizona Regional Haze FIPs: Modeling 
Protocol for Subject-to-BART and BART Control Options Analyses, EP-
D-07-102 WA5-12 Task 5, Institute for the Environment, University of 
North Carolina at Chapel Hill, March 14, 2012
    \88\ CALMET/CALPUFF Protocol for BART Exemption Screening 
Analysis for Class I Areas in the Western United States, Western 
Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph 
Morris, Abby Hoats and Yiqin Jia, August 15, 2006. Available on UCR 
Regional Modeling Center web site, BART CALPUFF Modeling, http://pah.cert.ucr.edu/aqm/308/bart.shtml.
    \89\ Revised BART Analysis for the Navajo Generating Station 
Units 1-3, ENSR Corporation, Document No. 05830-012-300, January 
2009, Salt River Project--Navajo Generating Station, Tempe, AZ.
---------------------------------------------------------------------------

    We performed separate CALPUFF modeling runs using baseline 
emissions, and using the emissions remaining after each candidate 
control technology was applied to the baseline. For baseline PM 
emissions, EPA used the WRAP's estimates. However, following procedures 
developed by the National Park Service,\90\ EPA divided those emissions 
into separate chemical species, and into separate coarse and fine 
particle fractions, to reflect better their varying visibility impacts.
---------------------------------------------------------------------------

    \90\ ``Particulate Matter Speciation'', National Park Service, 
2006. http://www.nature.nps.gov/air/Permits/ect/index.cfm.
---------------------------------------------------------------------------

    Although costs and emission reductions for each candidate BART 
control technology must necessarily be calculated separately for each 
emitting unit of a facility, emissions from all the units will be 
emitted into the air simultaneously. EPA modeled all units (stacks) and 
pollutants simultaneously. That is, even though only NOX 
BART alternatives were evaluated, SO2 and PM10 
emissions were also included in the modeling. Modeling all emissions 
from all the units accounts for the chemical interaction between 
multiple plumes, and between the plumes and the background 
concentrations. This also accounts for the facts that deciview benefits 
from individual units are not additive, and that each EPA BART proposal 
is for the facility as a whole.
b. Baseline Emissions
    Baseline NOX and SO2 emissions for the 
facilities were generally based on the maximum daily emissions from 
recent data in EPA's CAMD database, with data examined for 2008 to 
2011. The CAMD data derive from Continuous Emissions Monitoring in 
place at the facilities, and give the actual emissions that occurred. 
However, in cases where EPA is proposing to approve the BART emissions 
limits submitted by ADEQ, EPA used emission rates based on those 
limits, in lb/MMBtu, in combination with the maximum daily heat rate in 
MMBtu/hour from the CAMD data. The baseline emissions used by EPA 
reflect current fuels and control technologies in place at the 
facilities, as well as regulatory requirements the facilities will be 
required to meet independent of EPA's BART determination. This results 
in a more realistic estimate of current visibility impacts, and of the 
improvements that one would expect to result from implementation of 
EPA's proposed BART controls.

[[Page 42855]]

c. Emission Reductions for Alternative Controls
    For the CALPUFF modeling to assess visibility after application of 
a control technology, the percent control expected from the technology 
was applied to the baseline maximum daily emissions just described, as 
recommended in the BART Guidelines. As discussed elsewhere, LNB and 
SNCR each were assumed to reduce NOX by 30 percent, and SCR 
was assumed to reduce NOX by 90 percent. However, for SCR, 
we used a lower bound of 0.05 lb/MMBtu NOX, an emission rate 
that we have confidence is achievable, as discussed above under 
``Control Effectiveness''. The percent reduction actually applied to 
the maximum daily emissions was whatever was required to reduce the 
CAMD annual average emission factor down to this 0.05 lb/MMBtu 
NOX. For the various emitting units at the facilities, this 
ranged from 80 to 89 percent, instead of a full 90 percent reduction. 
Finally, in modeling the visibility impact of SCR, EPA accounted for 
the increased sulfuric acid emissions that occur when the SCR catalyst 
oxidizes SO2 present in the flue gas, using an estimation 
procedure developed by the Electric Power Research Institute\91\. 
(Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, 
Version 2010a, 1020636, Technical Update, Electric Power Research 
Institute, April 2010) This side effect of SCR's NOX 
reduction increases sulfate emissions and decreases the visibility 
benefits of SCR by around 5 percent.
---------------------------------------------------------------------------

    \91\ Estimating Total Sulfuric Acid Emissions from Stationary 
Power Plants, Version 2010a, 1020636, Technical Update, Electric 
Power Research Institute, April 2010.
---------------------------------------------------------------------------

d. Visibility Impacts
    CALPUFF Modeling: EPA followed the BART Guidelines in assessing 
visibility impacts. For each Class I area within 300 km of a facility, 
the CALPUFF model is used to simulate the baseline visibility impact of 
each facility and the impacts resulting after alternative controls are 
applied. However, certain aspects of assessing visibility with CALPUFF 
are not fully addressed in the Guidelines. These aspects include which 
``98th percentile'' from the model to use, the visibility calculation 
method (old vs. revised IMPROVE equation), and natural background 
concentrations (annual average versus best 20 percent of days).
    As recommended in the BART Guidelines, the 98th percentile daily 
impact in deciviews is used as the basic metric of visibility impact. 
(For a given Class I area, and for each modeled day, the model finds 
the maximum impact. From among the 365 maximum daily values, the 98th 
percentile is chosen, that is, the 8th highest.) Since multiple years 
of meteorology are modeled, there are at least three ways to use the 
model results: The maximum from among the 98th percentiles for the 
individual years 2001, 2002, and 2003 (``maximum''); the average of 
these three (``average''), or a single 98th percentile computed from 
all three years of data together (``merged'', the 22nd high among 1095 
daily values). The average and merged values are both unbiased 
estimates of the true 98th percentile; for this proposal EPA has used 
the merged value. The more conservative maximum value would be 
appropriate for a screening purpose, such as for determining whether a 
source is subject to BART.
    Visibility Calculation Method: The visibility calculation method 
relied on by EPA differed from that used by ADEQ. Visibility impacts 
may be simulated with CALPUFF using either the old or the revised 
IMPROVE equation for translating pollutant concentrations into 
deciviews; these are respectively CALPUFF visibility methods 6 and 8 
(implemented in the CALPOST post-processor). Many BART assessments were 
performed before method 8 was incorporated into CALPUFF, so method 6 
was generally for past assessments. However, in this proposal EPA is 
primarily relying on method 8. Method 8 is currently preferred by the 
Federal Land Managers; since the revised IMPROVE equation performs 
better at estimating visibility.\92\ For the facilities examined in 
this proposal, baseline impacts using method 6 would average about 10 
percent higher than those using method 8 (with a range of 3 percent 
lower to 22 percent higher depending on facility and Class I area; the 
effect for areas showing the largest benefit from control was similar 
to the average).
---------------------------------------------------------------------------

    \92\ Pitchford, Marc, 2006, ``New IMPROVE algorithm for 
estimating light extinction approved for use'', The IMPROVE 
Newsletter, Volume 14, Number 4, Air Resource Specialists, Inc.; Web 
page: http://vista.cira.colostate.edu/improve/Publications/news_letters.htm.
---------------------------------------------------------------------------

    Another CALPUFF choice is whether to calculate visibility impacts 
relative to annual average natural conditions, or relative to the best 
20 percent of natural background days; these may be referred to as 
``a'' and ``b''. For both ``a'' and ``b'', background concentrations 
for each Class I area are available in a Federal Land Managers' 
document.\93\ EPA Guidance allows for the use of either ``a'' or 
``b.''94 95 Since the annual average has worse visibility 
and higher deciviews than the best days do, a given facility impact 
will be smaller relative to the average than it is relative to the best 
days. That is, a facility's impact will stand out less under poorer 
visibility conditions. Thus, modeled facility impacts and control 
benefits appear smaller when ``a'' is used than when ``b'' is used. In 
this proposal, EPA is relying on ``b'', best 20 percent, consistent 
with initial EPA recommendations for BART assessments. For the 
facilities examined in this proposal, baseline impacts would average 
about 20 percent lower using background ``a'' than those using 
background ``b'' (with a range of 18 percent to 28 percent lower 
depending on facility and Class I area; the effect for areas showing 
the largest benefit from control was similar to the average).
---------------------------------------------------------------------------

    \93\ Federal Land Managers' Air Quality Related Values Work 
Group (FLAG) Phase I Report--Revised (2010), U.S. Forest Service, 
National Park Service, U.S. Fish and Wildlife Service, October 2010. 
Available on Web page http://www.nature.nps.gov/air/Permits/flag/.
    \94\ BART Guidelines, 70 FR 39125, July 6, 2005. ``Finally, 
these final BART guidelines use the natural visibility baseline for 
the 20 percent best visibility days for comparison to the `cause or 
contribute' applicability thresholds.''
    \95\ ``Regional Haze Regulations and Guidelines for Best 
Available Retrofit Technology (BART) Determinations'', memorandum 
from Joseph W. Paisie, EPA OAQPS, July 19, 2006, p.2.
---------------------------------------------------------------------------

    Considering visibility method and choice of background together, 
the BART visibility assessments relied on by ADEQ used method ``6a'', 
the old IMPROVE equation, and impacts relative to annual average 
natural conditions. This is a valid approach, and is consistent with 
EPA guidance.\96\ However, for this proposal, EPA considered all four 
combinations of IMPROVE equation version and natural background: 6a, 
6b, 8a, and 8b. EPA primarily relied on method ``8b'', that is, the 
revised IMPROVE equation, and impacts relative to the best 20 percent 
of natural background days. This is most consistent with our current 
understanding of how best to assess source specific visibility impacts. 
Combining the differences in visibility method and chosen background, 
for the facilities examined in this proposal, baseline impacts would 
average about 15 percent lower using method ``6a'' than those using 
method ``8b'' (with a range of 3 percent to 37 percent lower depending 
on facility and Class I area; the effect for areas showing the largest 
benefit from control was similar to the average). Results for all the 
various

[[Page 42856]]

visibility methods are available in the TSD.
---------------------------------------------------------------------------

    \96\ Additional Regional Haze Questions'', September 27, 2006 
Revision, EPA OAQPS.
---------------------------------------------------------------------------

 B. EPA's FIP BART Determinations

 1. Apache Units 2 and 3
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is 
described in VII.A.1., while issues unique to Apache Units 2 and 3 are 
described herein. In particular, we highlight below certain aspects of 
our analysis of this factor that differ from ADEQ's and AEPCO's 
analysis.
i. Selection of Baseline Period
    AEPCO's BART analysis used a 2002 to 2007 time period in order to 
establish its baseline NOX emissions. In our analysis, we 
decided to make use of the most recent Acid Rain Program emission data 
reported to CAMD, which, at the time that we began our analysis in 
2011, was the three-year period from 2008 to 2010. Based on CAMD 
documentation, no new control technology beyond the existing OFA system 
has been installed on either Apache Unit 2 or 3. We consider the use of 
this more recent baseline period to be a realistic depiction of 
anticipated future emissions.\97\
---------------------------------------------------------------------------

    \97\ BART Guidelines, 40 CFR part 51, appendix P, Section 
IV.D.4.d.
---------------------------------------------------------------------------

ii. SCR Control Efficiency
    In determining the control efficiency of SCR, we have relied upon 
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent 
than the level of performance used by ADEQ in its SIP. In the Apache 
BART analyses submitted to ADEQ, AEPCO indicated an SCR level of 
performance of 0.07 lb/MMBtu, but did not provide site-specific 
information describing how this emission rate was developed or 
discussing why a more stringent 0.05 lb/MMBtu level of performance 
could not be attained. Our control cost calculations for the SCR and 
LNB with OFA control options are based upon the control efficiency of 
SCR (combined with LNB) summarized in Table 15.

                   Table 15--Apache 2 and 3: EPA's SCR (Combined With LNB) Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                Baseline                           SCR control
                           Unit                               emission rate     SCR emission       efficiency
                                                             \1\  (lb/MMBtu)        rate          (percentage)
----------------------------------------------------------------------------------------------------------------
Apache 2..................................................             0.371              0.05                87
Apache 3..................................................             0.438              0.05                89
----------------------------------------------------------------------------------------------------------------
\1\ This baseline emission rate represents operation of OFA only.

iii. Capacity Factor
    As noted previously, AEPCO calculated annual emission estimates for 
its control scenarios, in tons per year, using annual capacity factors 
developed internally over an unspecified time frame.\98\ The annual 
capacity factors AEPCO used for each unit were 92 percent (Apache 2), 
and 87 percent (Apache 3). We have also calculated annual emission 
estimates for our control scenarios using capacity factors, but have 
used information developed from CAMD information, and over a more 
recent 2008 to 2011 time frame. The annual capacity factors we have 
used for each unit are 62 percent (Apache 2), and 71 percent (Apache 
3). We recognize that these capacity factors are lower than those used 
by AEPCO, and that by using these lower capacity factors, our estimates 
of total annual emissions (and correspondingly, the annual emission 
reductions) for each control scenario are lower than AEPCO's 
estimates.\99\ Since cost-effectiveness ($/ton) is calculated by 
dividing annual control costs ($/year) by annual emission reductions 
(tons/year), the use of emission reductions based on lower capacity 
factors will increase the cost per ton of pollutant reduced.
---------------------------------------------------------------------------

    \98\ As listed in Table 2-1 in Docket Items B-03 and B-04, 
Apache BART Analyses.
    \99\ We note that there are multiple reasons why our annual 
emission estimates (and estimates of emission removal) are lower 
than AEPCO's and ADEQ's estimates. We are not implying that the use 
of capacity factor is the sole, or even dominant, reason for this 
difference, simply that the use of lower capacity factors will 
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as 
based on a 2008 to 2011 time frame, in order to remain consistent with 
the time frame used to develop baseline annual emissions for Apache and 
the other power plants that are the subject of today's proposed action.
iv. Summary of Control Cost Estimates
    A summary of our control cost estimates for the various control 
technology options considered for Apache Units 2 and 3 is in Table 16. 
Detailed cost calculations, including our contractor's report and cost 
calculation spreadsheets, are available in our Technical Support 
Document.

                                               Table 16--Apache Units 2 and 3: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Emission rate                                 Cost-effectiveness  ($/ton)
                                                             Emission   --------------------------  Emissions               ----------------------------
                      Control option                        factor (lb/                              removed    Annual cost                 Incremental
                                                              MMBtu)       (lb/hr)       (tpy)        (tpy)        ($/yr)        Ave           (from
                                                                                                                                             previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Apache 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)...........................................         0.371          859        2,333  ...........  ...........  ...........  ..............
LNB+OFA..................................................         0.26           601        1,633          700    1,142,120        1,632  ..............
SNCR+LNB+OFA.............................................         0.18           421        1,143        1,190    2,652,841        2,230           3,084
SCR+LNB+OFA..............................................         0.05           116          314        2,019    5,869,299        2,908           3,881
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 42857]]

 
                                                                        Apache 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)...........................................         0.438          974        3,028  ...........  ...........  ...........  ..............
LNB+OFA..................................................         0.31           682        2,120          908    1,153,378        1,270  ..............
SNCR+LNB+OFA.............................................         0.22           477        1,484        1,544    2,968,611        1,922           2,854
SCR+LNB+OFA..............................................         0.05           111          346        2,683    6,103,078        2,275           2,754
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As seen in Table 16, our calculations indicate that the SCR-based 
control options have average cost-effectiveness values of $2,275/ton to 
$2,908/ton, which falls in a range that we consider cost-effective. In 
addition, our calculations indicate that the SCR-based control options 
have an incremental cost-effectiveness of $2,754/ton to $3,881/ton, 
which is also in a range that we would consider cost-effective. As a 
result, our analysis of this factor indicates that the costs of 
compliance (average or incremental) are not sufficiently large to 
warrant eliminating any of the control options from consideration.
b. Visibility Improvement
    The overall visibility modeling approach was described above; 
aspects of the modeling specific to Apache are described here. EPA is 
proposing a NOX BART determination only for Apache units 2 
and 3, but Unit 1 was also included in the modeling runs for greater 
realism in assessing the full facility's visibility impacts.\100\ For 
Unit 1's NOX emissions, ADEQ's emission factor of 0.56 lb/
MMBtu was combined with the maximum MMBtu/hr heat rate from EPA's CAMD 
database for 2008 to 2010. The baseline emissions used for these units 
were the maximum daily emissions in lb/hr from 2008 to 2010; the maxima 
occurred in early 2008. The base case reflects only OFA as the control 
in place.
---------------------------------------------------------------------------

    \100\ Apache Unit 4, which consists of four simple-cycle gas 
turbines, was not included in the modeling because its 
NOX emissions are less than 1 percent of the emissions of 
units 2 and 3, and are therefore expected to have a de minimis 
effect on modeled visibility impacts.
---------------------------------------------------------------------------

    EPA evaluated LNB, SNCR (including LNB), and SCR (including LNB) 
applied to both Units 2 and 3; as mentioned above the SCR simulation 
accounted for the increase in sulfuric acid emissions due to catalyst 
oxidation of SO2. SCR was assumed to give a control 
effectiveness of 87 percent and 89 percent for Units 2 and 3, 
respectively (less than 90 percent due to the 0.05 lb/MMBtu 
NOX lower limit assumed for SCR). The nine Class I areas 
within 300 km of Apache were modeled; they are in the states of Arizona 
and New Mexico. The 98th percentile of delta deciviews over all three 
years of data was computed for each area and emission scenario.
    Table 17 shows the impact for the base case, and the improvement 
from that baseline impact when controls are applied, all in deciviews, 
for each area. The Class I area types are National Monument (NM), 
Wilderness Area (WA), and National Park (NP). Also shown are the 
cumulative deciviews, the simple sum of impacts or improvements over 
all the Class I areas, and the number of areas with a baseline impact 
or improvement of at least 0.5 dv. Finally, the table includes two 
``dollars per deciview'' measures of cost-effectiveness, both of which 
take the annual cost of the control in millions of dollars per year, 
and divide by an improvement in deciviews. For the first metric, ``$/
max dv'', cost is divided by the deciview improvement at the Class I 
area with the greatest improvement. The second metric, ``$/cumulative 
dv'', divides cost by the cumulative deciview improvement. In assessing 
the degree of visibility improvement from controls, EPA relied heavily 
on the maximum dv improvement and the number of areas showing 
improvement, with cumulative improvement providing a supplemental 
measure that combines information on the number of areas and on 
individual area improvement. The dollars per deciview metrics provided 
information supplemental to the dollars per ton that was considered in 
the cost factor.
    In its comments on Arizona's proposed Regional Haze SIP, the 
National Park Service noted that:

    Compared to the typical control cost analysis in which estimates 
fall into the range of $2,000-$10,000 per ton of pollutant removed, 
spending millions of dollars per deciview (dv) to improve visibility 
may appear extraordinarily expensive. However, our compilation of 
BART analyses across the U.S. reveals that the average cost per dv 
proposed by either a state or a BART source is $14-$18 million.\101\

    \101\ Arizona Regional Haze SIP, Appendix E, Public Process, NPS 
General BART Comments on ADEQ BART Analyses (November 29, 2010), p. 
4.
---------------------------------------------------------------------------

While we do not necessarily consider $14 to $18 million/dv as being a 
reasonable range in all cases, we note that for all of the 
NOX control options, including SCR, both the $/max dv and 
the $/cumulative dv are well below this range.
    The area with the greatest dv improvement was the Chiricahua 
Wilderness Area; the improvement from LNB was 0.5 dv, from SNCR was 1 
dv, and from SCR was 1.6 dv. Any of these improvements would contribute 
to improved visibility, with SCR being the superior option for 
visibility. The corresponding cumulative improvements are 2.1, 3.8, and 
6.5. Both SNCR and SCR give improvements exceeding 0.5 dv at four 
areas, but for SCR the improvements at those areas also exceed a full 1 
dv. The improvements from SCR are substantially greater than for the 
other candidate controls. The modeled degree of visibility improvement 
supports SCR as BART for Apache.

[[Page 42858]]



                 Table 17--Apache Units 2 and 3: EPA'S Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                     Baseline       Improvement     Improvement     Improvement
                  Class I Area                      impact (dv)    from LNB (dv)  from SNCR (dv)   from SCR (dv)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM...................................            3.41            0.44            0.82            1.51
Chiricahua WA...................................            3.46            0.53            1.00            1.59
Galiuro WA......................................            2.22            0.39            0.65            1.10
Gila WA.........................................            0.63            0.14            0.22            0.37
Mazatzal WA.....................................            0.28            0.05            0.09            0.14
Mount Baldy WA..................................            0.28            0.07            0.11            0.18
Saguaro NP......................................            2.49            0.38            0.66            1.16
Sierra Ancha WA.................................            0.29            0.06            0.10            0.14
Superstition WA.................................            0.61            0.10            0.19            0.31
Cumulative dv...................................           13.67            2.14            3.83            6.51
 areas >=0.5...........................               6            1               4               4
$/max dv, millions..............................  ..............           $4.8            $6.0            $8.7
$/cumulative dv, millions.......................  ..............           $1.2            $1.6            $2.1
----------------------------------------------------------------------------------------------------------------

c. EPA's BART Determination
    In considering the results of the five-factor analysis, we note 
that the remaining useful life of the source, as indicated previously 
by the plant economic life of Apache Units 2 and 3, is incorporated 
into control cost calculations as a 20-year amortization period. In 
addition, the presence of existing pollution control technology is 
reflected in the cost and visibility factors as a result of selection 
of the baseline period for cost calculations and visibility modeling. 
For Apache Units 2 and 3, a baseline period (2008 to 2010) was selected 
that reflects the currently existing pollution control technology 
(OFA). In examining energy and non-air quality impacts, we note certain 
potential impacts resulting from the use of ammonia injection 
associated with the SNCR and SCR control options, but do not consider 
these impacts sufficient enough to warrant eliminating any of the 
available control technologies.
    Our consideration of degree of visibility improvement focuses 
primarily on the improvement from base case impacts associated with 
each control option. While each of the available NOX control 
options achieves some degree of visibility improvement, we consider the 
improvement associated with the most stringent option, SCR with LNB and 
OFA, to be substantial. Our consideration of cost of compliance focuses 
primarily on the cost-effectiveness of each control option, as measured 
in cost per ton and incremental cost per ton of each control option. 
Despite the fact that the most stringent option, SCR with LNB and OFA, 
is the most expensive of the available control options, we consider it 
cost-effective on an average basis as well as on an incremental basis 
when compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control 
option, SCR with LNB and OFA, to be both cost-effective and to result 
in substantial visibility improvement, and that the energy and non-air 
quality impacts are not sufficient to warrant eliminating it from 
consideration. Therefore, the results of our five-factor analysis 
indicate that NOX BART for Apache Units 2 and 3 is SCR with 
LNB and OFA.
    However, we note that the BART guidelines state that:

    Even if the control technology is cost-effective, there may be 
cases where the installation of controls would affect the viability 
of continued plant operations. [[hellip]]You may take into 
consideration the conditions of the plant and the economic effects 
of requiring the use of a control technology. Where these effects 
are judged to have a severe impact on plant operations you may 
consider them in the selection process, but you may wish to provide 
an economic analysis that demonstrates, in sufficient detail for 
public review, the specific economic effects, parameters, and 
reasoning.'' \102\
---------------------------------------------------------------------------

    \102\ 70 FR 39171.

As explained in Section IX.C below, because AEPCO is a ``small 
entity'', as defined under the Regulatory Flexibility Act, we have 
conducted an initial assessment of the potential adverse impacts on 
AEPCO of requiring SCR with LNB and OFA. Using publicly available 
information, EPA estimates that the annualized cost of requiring SCR in 
Units 1 and 2 would likely be in the range of 3 percent of AEPCO's 
assets and between 6 and 7 percent of AEPCO's annual sales. The 
projected costs of SCR with LNB and OFA are approximately $12 million 
per year. This exceeds AEPCO's net margins of $9.5 million in 2010 and 
$1.9 million in 2011.\103\
---------------------------------------------------------------------------

    \103\ See Docket Item H-1Arizona Electric Power Cooperative, 
Inc. Annual Report Electric for Year Ending December 31, 2011 
submitted to Arizona Corporation Commission Utilities Division, 
available at http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf.
---------------------------------------------------------------------------

    In addition to conducting this initial economic impact assessment, 
we requested information from AEPCO on the economics of operating 
Apache Generating Station and what impact the installation of SCR may 
have on the economics of operating Apache Generating Station. We have 
just received a description of plant conditions and potential economic 
effects and are placing this information in the docket for this 
action.\104\ We will consider this information and any additional 
information received during the comment period as part of our final 
action. If our analysis of this information indicates that installation 
of SCR will have a severe impact on the economics of operating Apache 
Generating Station, we will incorporate such considerations in our 
selection of BART.
---------------------------------------------------------------------------

    \104\ Docket Item C-16, Letter from Michelle Freeark (AEPCO) to 
Deborah Jordan (EPA), AEPCO's Comments on BART for Apache Generating 
Station, June 29, 2012.
---------------------------------------------------------------------------

    Nonetheless, based on the available control technologies and the 
five factors discussed above, EPA is proposing to require Apache 
Generating Station to meet an emission limit for NOX on 
Units 2 and 3 of 0.050 lb/MMBtu. Each of these emission limits is based 
on a rolling 30-boiler-operating-day average.
2. Cholla Units 2, 3 and 4
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is 
described in section VII.A.1 above. Issues unique to Cholla Units 2, 3 
and 4 are explained

[[Page 42859]]

herein. There are several aspects of our analysis of this factor that 
differ from ADEQ's and APS' analysis and we discuss the most important 
of these below.
i. Selection of Baseline Period
    APS' BART analysis used a 2001-03 time period in order to establish 
its baseline NOX emissions. As noted previously, the 
NOX control technology present on Cholla Units 2 through 4 
during that time period was close-coupled over fire air (COFA). APS has 
since installed low-NOX burners with separated over fire air 
(SOFA) on Cholla Units 2 through 4. In order to properly consider the 
second BART factor (pollution control equipment in use at the source) 
and to ensure that actual conditions at the plant were reflected in our 
baseline NOX emissions, we decided to make use of the most 
recent Acid Rain Program emission data reported to CAMD, which, at the 
time that we began our analysis in 2011, was the three-year period from 
2008 to 2010. Based on CAMD documentation, the low-NOX 
burners were installed on the Cholla units at different times during 
2008 and 2009, making it necessary for us to clearly distinguish 
between the pre-LNB and post-LNB periods of emission data for each 
unit.
    The use of a 2008 to 2010 baseline was, however, complicated by the 
fact that the Cholla plant operates under a new coal contract for Lee 
Ranch/El Segundo coal, which is a higher NOX-emitting coal 
than what was previously used.\105\ This coal contract indicates that 
steadily increasing minimum quantities of coal shall be delivered, 
starting with 325,000 tons in 2006 and up to 3,700,000 tons in 2010. 
This gradual transition to the newer, higher-NOX emitting 
coal source made it difficult to determine the extent to which a 
particular year's emissions were representative of anticipated annual 
emissions. In the absence of more detailed fuel usage records on a per-
unit basis, it was not possible for us to identify which units may have 
operated using the newer coal during the 2006 to 2010 transition period 
to the newer coal type. We note, however, that the coal contract 
specifically states that, for 2010 to 2024, no later than July 1 of 
each year, the buyer shall indicate the annual tonnage for the 
following calendar year, and that in no case shall the annual tonnage 
be less than 3,700,000 tons. As a result, 2011 represents the first 
complete calendar year at which we can be certain that the Cholla plant 
operated at the new coal contract's ``full'' minimum purchase quantity 
of 3,700,000 tons per year.
---------------------------------------------------------------------------

    \105\ A copy of the coal contract, including obligation amounts 
and coal quality, can be found in Docket Item B-09, ``Additional APS 
Cholla BART response'', Appendix B.
---------------------------------------------------------------------------

    Since 2011 Acid Rain Program emission data became available during 
the intervening time between the start of our analysis and our proposed 
action today, we have selected 2011 as the time period for establishing 
baseline annual NOX emissions. Although this represents only 
a single year of data, we believe the use of this more recent baseline 
period represents the most realistic depiction of anticipated annual 
emissions, as it is the only time period that ensures each of the 
Cholla units is operating using the new coal and LNB with SOFA.
ii. SCR Control Efficiency
    In determining the control efficiency of SCR, we have relied upon 
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent 
than the level of performance used by ADEQ in its SIP. In the Cholla 
BART analysis submitted to ADEQ, APS indicated an SCR level of 
performance of 0.07 lb/MMBtu, but did not provide site-specific 
information describing how this emission rate was developed or 
discussing why a more stringent 0.05 lb/MMBtu level of performance 
could not be attained. Our control cost calculations for the SCR and 
LNB with OFA control options are based upon the SCR control 
efficiencies summarized below. These control efficiencies reflect the 
emission reductions associated with controlling from an annual average 
baseline emission rate that represents LNB with OFA (as described 
previously) down to an SCR emission rate of 0.05 lb/MMBtu.

                         Table 18--Cholla Units 2, 3 and 4: EPA's Scr Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                Baseline                           SCR control
                           Unit                              emission rate 1    SCR emission       efficiency
                                                               (lb/MMBtu)           rate          (percentage)
----------------------------------------------------------------------------------------------------------------
Cholla 2..................................................             0.295              0.05                83
Cholla 3..................................................             0.254              0.05                80
Cholla 4..................................................             0.260              0.05                81
----------------------------------------------------------------------------------------------------------------
1 As noted previously, this baseline emission rate reflects the installation of LNB+OFA

iii. Capacity Factor
    As noted previously, APS calculated annual emission estimates for 
its control scenarios, in tons per year, using annual capacity factors 
based on Acid Rain Program data from CAMD over a 2001 to 2006 time 
frame.\106\ The annual capacity factors APS used for each unit were 91 
percent (Cholla 2), 86 percent (Cholla 3), and 93 percent (Cholla 4). 
We have also calculated annual emission estimates for our control 
scenarios using capacity factors developed from CAMD information, but 
have instead used a more recent 2008 to 2011 time frame. The annual 
capacity factors we have used for each unit are 74 percent (Cholla 2), 
75 percent (Cholla 3), and 71 percent (Cholla 4). We recognize that 
these capacity factors are lower than those used by APS, and that by 
using these lower capacity factors, our estimates of total annual 
emissions (and correspondingly, the annual emission reductions) for 
each control scenario are lower than APS' estimates.\107\ Since cost-
effectiveness ($/ton) is calculated by dividing annual control costs 
($/year) by annual emission reductions (tons/year), the use of emission 
reductions based on lower capacity factors will increase the cost per 
ton of pollutant reduced.
---------------------------------------------------------------------------

    \106\ As listed in Table 2-1 in Docket Items B-06 through B-08, 
Cholla BART Analyses.
    \107\ We note that there are multiple reasons why our annual 
emission estimates (and estimates of emission removal) are lower 
than APS' and ADEQ's estimates. We are not implying that the use of 
capacity factor is the sole, or even dominant, reason for this 
difference, simply that the use of lower capacity factors will 
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as 
based on a 2008 to 2011 time frame, in order to remain consistent with 
the time frame used to develop baseline annual emissions for Cholla and 
the other

[[Page 42860]]

power plants that are the subject of today's proposed action.\108\
---------------------------------------------------------------------------

    \108\ We recognize that there are more aggressive approaches we 
could adopt that could justify the use of higher capacity factors, 
which would thereby lower the cost per ton of pollutant reduced. For 
example, instead of using historical data to develop a capacity 
factor value for each unit, we could use a single capacity factor 
value for each unit, one that represented a reasonable depiction of 
anticipated annual baseload operations. Alternately, we could also 
use the capacity factor estimates from APS' Cholla BART analyses, as 
based on a 2001-06 time frame, or develop new capacity factors based 
on a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------

iv. Summary of Control Costs
    A summary of our control cost estimates for the various control 
technology options considered for is included below. Detailed cost 
calculations, including our contractor's report and cost calculation 
spreadsheets, can be found in our TSD.

                                              Table 19--Cholla Units 2, 3 And 4: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Emission rate                                  Cost-effectiveness ($/ton)
                                                             Emission   --------------------------  Emissions               ----------------------------
                      Control option                        factor (lb/                              removed    Annual cost                 Incremental
                                                              MMBtu)       (lb/hr)       (tpy)        (tpy)        ($/yr)        Ave           (from
                                                                                                                                             previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.295          892        2,890  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.21           624        2,023          867    2,482,318        2,863  ..............
SCR+LNB+OFA..............................................         0.05           151          490        2,400    7,475,028        3,114           3,257
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.254          885        2,908  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.18           620        2,036          872    2,533,432        2,904  ..............
SCR+LNB+OFA..............................................         0.05           174          572        2,337    8,113,131        3,472           3,811
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.260         1144        3,609  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.18           801        2,526        1,083    3,185,822        2,943  ..............
SCR+LNB+OFA..............................................         0.05           220          694        2,915    9,894,796        3,395           3,661
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As indicated in Table 19, our calculations indicate that the SCR-
based control options have average cost-effectiveness values of $3,114/
ton to $3,472/ton, which falls in a range that we would consider cost-
effective. In addition, our calculations indicate that the SCR-based 
control options have an incremental cost-effectiveness of $3,257/ton to 
$3,811/ton, which is also in a range that we would consider cost-
effective. As a result, our analysis of this factor indicates that the 
costs of compliance (average or incremental) are not sufficiently large 
to warrant eliminating any of the control options from consideration.
b. Visibility Improvement
    The overall visibility modeling approach was described above; 
aspects of the modeling specific to Cholla are described here. EPA made 
a NOX BART determination for Cholla Units 2, 3 and 4, but 
Unit 1 (which is not BART-eligible) was also included in the modeling 
runs for greater realism in assessing the full facility's visibility 
impacts. For Unit 1's NOX emissions, the maximum daily 
emissions from EPA's CAMD database for 2008 to 2010 were used; the 
maximum occurred in early 2008. LNB was installed on Units 2 and 4 
early in 2008, and on Unit 3 in mid-2009; for a realistic base case, 
the baseline emissions used for these units were the maximum daily 
emissions in lb/hr from 2008-2010 occurring after the respective LNB 
installation dates. The maximum for unit 2 occurred in mid-2009, and 
the maxima for Units 2 and 3 occurred in late 2010. The base case 
reflects LNB as the control in place.
    EPA evaluated SNCR (including LNB) and SCR (including LNB) applied 
to Units 2, 3 and 4. SCR was assumed to give a control effectiveness of 
83 percent, 80 percent, and 81 percent for units 2, 3 and 4, 
respectively (less than 90 percent due to the 0.05 lb/MMBtu 
NOX lower limit assumed for SCR). For Cholla, the increase 
in sulfuric acid due to SCR was not simulated, because the baghouse 
(fabric filter) installed for particulate matter control would reduce 
this increased sulfate by 99 percent, resulting in a negligible effect 
on the visibility estimate. The 13 Class I areas within 300 km of 
Cholla were modeled; they are in the states of Arizona, Colorado, New 
Mexico, and Utah. The 98th percentile delta deciview using all three 
years of data together was computed for each area and emission 
scenario.
    Table 20 shows baseline visibility impacts and the visibility 
improvement when controls are applied; the various table entries are 
described above in the discussion of the comparable table for Apache. 
The area with the greatest dv improvement was the Petrified Forest 
National Park; the improvement from SNCR was just under 0.5 dv and from 
SCR was 1.3 dv. Either of these improvements would contribute to 
improved visibility, with SCR being the superior option for visibility. 
The corresponding cumulative improvements are 2.7 and 7.2. Only SCR 
gives improvements exceeding 0.5 dv, and it does so at eight areas, two 
of which have improvements above a full 1 dv. The modeled degree of 
visibility

[[Page 42861]]

improvements supports SCR as BART for Cholla.

                Table 20--Cholla Units 2, 3 and 4: EPA's Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                           Baseline impact   Improvement from   Improvement from
                      Class I area                              (dv)            SNCR (dv)           SCR (dv)
----------------------------------------------------------------------------------------------------------------
Capitol Reef NP.........................................              1.46               0.27               0.76
Galiuro WA..............................................              0.45               0.05               0.14
Gila WA.................................................              0.70               0.09               0.22
Grand Canyon NP.........................................              2.22               0.37               1.06
Mazatzal WA.............................................              1.19               0.16               0.43
Mesa Verde NP...........................................              1.34               0.26               0.70
Mount Baldy WA..........................................              1.21               0.27               0.52
Petrified Forest NP.....................................              4.53               0.47               1.34
Pine Mountain WA........................................              0.85               0.12               0.31
Saguaro NP..............................................              0.30               0.02               0.05
Sierra Ancha WA.........................................              1.36               0.20               0.51
Superstition WA.........................................              1.27               0.17               0.51
Sycamore Canyon WA......................................              1.42               0.27               0.68
Cumulative dv...........................................             18.30               2.71               7.21
 areas >=0.5...................................                11               0                  8
$/max dv, millions......................................  ................             $17.8              $20.8
$/cumulative dv, millions...............................  ................              $3.1               $3.8
----------------------------------------------------------------------------------------------------------------

c. EPA's BART Determination
    As noted above, the remaining useful life of the source is 
incorporated into control cost calculations as a 20-year amortization 
period. In addition, the presence of existing pollution control 
technology is reflected in the cost and visibility factors as a result 
of selection of the baseline period for cost calculations and 
visibility modeling. For Cholla Units 2, 3, and 4, a baseline period 
(2011) was selected that reflects the currently existing pollution 
control technology (LNB with OFA). In examining energy and non-air 
quality impacts, we note certain potential impacts resulting from the 
use of ammonia injection associated with the SNCR and SCR control 
options, but do not consider these impacts sufficient enough to warrant 
eliminating any of the available control technologies.
    Our consideration of degree of visibility improvement focuses 
primarily on the improvement from base case impacts associated with 
each control option. While each of the available NOX control 
options achieves some degree of visibility improvement, we consider the 
improvement associated with the most stringent option, SCR with LNB and 
OFA, to be substantial.
    Our consideration of cost of compliance focuses primarily on the 
cost-effectiveness of each control option, as measured in cost per ton 
and incremental cost per ton of each control option. Despite the fact 
that the most stringent option, SCR with LNB and OFA, is the most 
expensive of the available control options, we consider it cost-
effective on average basis as well as on an incremental basis when 
compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control 
option, SCR with LNB and OFA, to be both cost-effective and to result 
in substantial visibility improvement, and that the energy and non-air 
quality impacts are not sufficient to warrant eliminating it from 
consideration. Therefore, we propose to determine that NOX 
BART for Cholla Units 2, 3, and 4 is SCR with LNB and OFA, with an 
associated emission limit for NOX on each of Units 2, 3, and 
4 of 0.050 pounds per million British thermal units (lb/MMBtu), based 
on a rolling 30-boiler-operating-day average.
3. Coronado Units 1 and 2
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is 
described in section VII.A.2 above, while considerations unique to 
Coronado Units 1 and 2 are explained herein. There are several aspects 
of our analysis of this factor that differ from ADEQ's and SRP's 
analysis and we describe the most important elements below.
i. Selection of Baseline Period and Baseline Control Technology
    SRP's BART analysis used a 2001-03 time period in order to 
establish its baseline NOX emissions. Since that time 
period, SRP has since installed LNB with OFA on Coronado Units 1 and 2. 
In order to ensure that actual conditions at the plant are reflected in 
our baseline NOX emissions, we decided to make use of the 
most recent Acid Rain Program emission data reported to CAMD, which, at 
the time that we began our analysis in 2011, was the three-year period 
from CY2008-10. Based on CAMD documentation, the low-NOX 
burners were installed on Coronado Unit 1 on May 16, 2009, making it 
necessary for us to clearly distinguish between the pre-LNB and post-
LNB periods of emission data for Coronado Unit 1. In our analysis, we 
have decided to make use of CAMD emission data corresponding to the 
post-LNB period extending from May 16, 2009 to December 31, 2010. We 
believe the use of this more recent baseline period represents the most 
realistic depiction of anticipated annual emissions, as it reflects 
operation of Coronado Unit 1 with LNB and OFA.
    For Coronado Unit 2, we note that a consent decree between SRP and 
EPA requires the installation of SCR and compliance with an emission 
limit of 0.080 lb/MMBtu (30-day rolling average) by June 1, 2014.\109\ 
Although we realize this SCR system has not yet been installed on 
Coronado Unit 2, this limit is federally enforceable and represents a 
realistic depiction of anticipated future emissions.\110\ As a result, 
we consider 0.080 lb/MMBtu to be the baseline emission rate in our BART 
analysis and are examining only one control scenario

[[Page 42862]]

in our analysis for Unit 2, SCR at a more stringent emission rate of 
0.050 lb/MMBtu.\111\
---------------------------------------------------------------------------

    \109\ See Docket Item G-01, ``Consent Decree Between U.S. and 
SRP (final as entered).'' See also ADEQ Title V Permit Renewal 
Number 52639, SRP--Coronado Generating Station, section II.E.1.a.iii 
(December 06, 2011).
    \110\ See 40 CFR part 51, appendix Y, Section IV.D.4.d.
    \111\ A discussion of our rationale for considering SCR at an 
emission rate of 0.05 lb/MMBtu can be found in Section VII.A.2 
(Control Effectiveness) of this notice.
---------------------------------------------------------------------------

ii. SCR Control Efficiency
    In determining the control efficiency of SCR in our BART analysis, 
we have relied upon an SCR level of performance of 0.05 lb/MMBtu, which 
is more stringent than the level of performance used by ADEQ in its 
SIP, or by SRP in its Coronado BART analysis. In the Coronado BART 
analysis submitted to ADEQ, SRP indicated an SCR level of performance 
of 0.08 lb/MMBtu, and noted that ``If inlet NOX 
concentrations are less than 250 ppmvd, SCR can achieve NOX 
control efficiencies ranging only from 70 to 80 percent.'' \112\ SRP 
suggests that the 75 percent reduction (and associated 0.08 lb/MMBtu 
emission rate) it estimates for SCR is the result of low inlet 
NOX concentration, but does not provide specific information 
regarding inlet NOX concentration at Coronado, or how a 75 
percent reduction was determined. Our control cost calculations for the 
SCR control option at Coronado Unit 1 are based upon the SCR control 
efficiency summarized below. This control efficiency reflects the 
emission reductions associated with controlling from an annual average 
baseline emission rate that represents LNB+OFA (as described 
previously) down to an SCR emission rate of 0.05 lb/MMBtu.
---------------------------------------------------------------------------

    \112\ See Docket Item B-10, SRP Coronado BART Analysis, page 4-5

                             Table 21--Coronado Unit 1: EPA's SCR Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                              Baseline                            SCR control
                        Unit No.                         emission rate (lb/ SCR emission rate      efficiency
                                                               MMBtu)                             (percentage)
----------------------------------------------------------------------------------------------------------------
Coronado 1.............................................             0.303               0.05               83.5
----------------------------------------------------------------------------------------------------------------

iii. Capacity Factor
    SRP did not calculate annual emission estimates for its control 
scenarios, in tons per year, in its BART analysis submitted to ADEQ. In 
developing its RH SIP, ADEQ estimated annual emission reductions based 
upon 8,760 hours/year of operation (i.e., 100 percent capacity factor). 
We have calculated annual emission estimates for our control scenarios 
using capacity factors developed over a CY2008-11 time frame. The 
annual capacity factors we have used for each unit are 81 percent 
(Coronado 1), and 89 percent (Coronado 2). We recognize that these 
capacity factors are lower than those used by ADEQ, and that by using 
these lower capacity factors, our estimates of total annual emissions 
(and correspondingly, the annual emission reductions) for each control 
scenario are lower than ADEQ's estimates.\113\ Since cost-effectiveness 
($/ton) is calculated by dividing annual control costs ($/year) by 
annual emission reductions (tons/year), the use of emission reductions 
based on lower capacity factors will increase the cost per ton of 
pollutant reduced.
---------------------------------------------------------------------------

    \113\ We note that there are multiple reasons why our annual 
emission estimates (and estimates of emission removal) are lower 
than AEPCO's and ADEQ's estimates. We are not implying that the use 
of capacity factor is the sole, or even dominant, reason for this 
difference, simply that the use of lower capacity factors will 
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as 
based on a 2008 to 2011 time frame, in order to remain consistent with 
the time frame used to develop baseline annual emissions for Coronado 
and the other power plants that are the subject of today's proposed 
action.\114\
---------------------------------------------------------------------------

    \114\ We recognize that there are more aggressive approaches we 
could adopt that could justify the use of higher capacity factors, 
which would thereby lower the cost per ton of pollutant reduced. For 
example, instead of using historical data to develop a capacity 
factor value for each unit, we could use a single capacity factor 
value for each unit, one that represented a reasonable depiction of 
anticipated annual baseload operations. Alternately, we could also 
use a 100% capacity factor, or develop new capacity factors based on 
a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------

iv. Summary and Conclusions Regarding Costs of Control
    A summary of our control cost estimates for the various control 
technology options considered for Coronado Units 1 and 2 is in Table 
22. Detailed cost calculations, including our contractor's report and 
cost calculation spreadsheets, are in our TSD.

                                              Table 22--Coronado Units 1 and 2: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Emission rate                                  Cost-effectiveness  ($/ton)
                                                           Emission   --------------------------  Emissions   Annual cost ------------------------------
                     Control option                       factor (lb/                              removed       ($/yr)                    Incremental
                                                            MMBtu)       (lb/hr)       (tpy)        (tpy)                    Average     (from previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Coronado 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA....................................................                         NA; LNB+OFA is the currently installed technology
                                                        ------------------------------------------------------------------------------------------------
LNB+OFA (baseline).....................................         0.303        1,308        4,639  ...........  ...........  ...........  ................
SNCR+LNB+OFA...........................................         0.21           915        3,248        1,392    3,825,556        2,749  ................
SCR+LNB+OFA............................................         0.05           216          766        3,874    9,315,313        2,405             2,212
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Coronado 2
____________________________________________________________________________
[email protected] lb/MMBtu......................................         0.08           319        1,242  ...........          \1\  ...........  ................
(baseline).............................................                                                         8,721,636
[email protected] lb/MMBtu......................................         0.05           199          776          466    8,993,116  ...........               583
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Annual cost for the baseline scenario is provided here only to allow calculation of the incremental cost associated with a control option of
  [email protected] lb/MMBtu.


[[Page 42863]]

    For Coronado 1, our calculations indicate that the SCR-based 
control option has an average cost-effectiveness value of $2,405/ton 
and an incremental cost-effectiveness of $2,212/ton, both of which we 
consider cost-effective. As described further below, our analysis for 
Coronado 2 relied upon SCR at an emission rate of 0.08 lb/MMBtu as a 
baseline scenario. As a result, the only control option we examined for 
Coronado 2 was an SCR-based option at a more stringent level of 
performance, 0.05 lb/MMBtu. Our initial analysis indicates that the 
incremental cost-effectiveness of such an option is $583/ton, making it 
a control option that we would consider cost-effective. However, we 
received information from SRP indicating that design and construction 
of the SCR system for this unit are well under way. In its letter, SRP 
states that ``if SRP were required to abandon the current design, incur 
procurement losses, possibly remove foundations, and undertake new 
design and procurement, such steps would vastly increase the cost of 
the SCR retrofit.'' Since these types of additional costs were not 
factored into our original analysis, the average and incremental cost-
effectiveness of requiring Coronado Unit 2 to meet an emissions limit 
of 0.050 lb/MMBtu may in fact be greater than indicated by our 
analysis. However, we intend to request further documentation in order 
to determine the extent of these costs and how they would affect our 
cost-effectiveness calculations. We will include all non-CBI material 
received in the docket for this action and will consider it as part of 
our final action. We are specifically interested in information from 
SRP concerning the number of layers of catalyst for the SCR at Unit 2, 
how they plan to manage replacement of the catalyst, and whether the 
catalyst could be installed and managed to allow Unit 2 to meet a lower 
emission limit than 0.08 lb/MMBtu.
    Thus, our initial analysis of this factor indicates that the costs 
of compliance (average or incremental) are not sufficiently large to 
warrant eliminating any of the control options from consideration. 
However, we note that, based on preliminary information received from 
SRP, the average and incremental costs of achieving an emission rate of 
0.050 lb/MMBtu at Unit 2 may be much greater than our initial analysis 
suggests.
b. Visibility Improvement
    The overall modeling approach was described above; aspects of the 
modeling specific to Coronado are described here. LNB was installed on 
Unit 1 in mid-2009, and on Unit 2 in mid-2011. For Unit 1's 
NOX emissions, the maximum daily emissions in EPA's CAMD 
database for 2008 to 2010 was used; the maximum post-LNB installation 
emissions occurred in late 2010. For unit 2 emissions, the consent 
decree-mandated NOX emission limit of 0.08 lb/MMBtu was 
combined with the maximum heat rate from 2008-2010 CAMD data, which 
occurred in late 2008. Since this limit has a 30-day averaging time, 
daily emissions may be larger than the emissions EPA modeled; the 
emission and visibility benefit would also be larger. Thus, visibility 
benefits from control applied to the base case may actually be larger 
than presented here. The base case reflects LNB as the control in place 
on Unit 1, and SCR at 0.08 lb/MMBtu NOX on Unit 2.
    EPA evaluated SNCR applied to Unit 1, and SCR at 0.05 lb/MMBtu 
applied to both Units 1 and 2. SCR was assumed to give a control 
effectiveness of 83.5 percent for unit 1 (less than 90 percent due to 
the 0.05 lb/MMBtu NOX lower limit assumed for SCR). SCR at 
0.05 lb/MMBtu NOX was assumed to give a control 
effectiveness of 37.5 percent over the base case 0.08 lb/MMBtu. As 
mentioned above, the SCR simulation accounted for the increase in 
sulfuric acid emissions due to catalyst oxidation of SO2. 
However, the simulation with SNCR applied to unit 1 did not account for 
this effect. If this additional Unit 2 sulfate were accounted for, it 
could make some background ammonia unavailable to form visibility-
affecting particulate from Unit 1's NOX emissions, thus 
reducing the visibility impact and also the visibility benefit from 
SNCR. We expect this to have very little effect on the estimated SNCR 
visibility benefit, since it was computed relative to an alternative 
base case that likewise did not include the catalyst oxidation effect, 
but the visibility benefits from SNCR may thus be slightly less than 
reported here, weakening the case for SNCR.
    Sixteen Class I areas within 300 km of Coronado were modeled; they 
are in the states of Arizona, Colorado, and New Mexico. A 17th area, 
the Bosque del Apache Wilderness Area in New Mexico, was inadvertently 
omitted. Since it is in the same general direction from Coronado as the 
Gila Wilderness Area, but farther way, visibility impacts and control 
benefits at Bosque del Apache are likely to be lower than for Gila, so 
the maximum dv benefit would not be affected by this omission. However, 
the cumulative impacts and benefits would be higher than reported here 
since Bosque del Apache is omitted from the sum. The 98th percentile 
delta deciviews over all three years of data were computed for each 
area and emission scenario.
    Table 23 shows baseline visibility impacts and the visibility 
improvement when controls are applied; the various table entries are 
described above in the discussion of the comparable table for Apache. 
The area with the greatest dv improvement was the Gila Wilderness Area; 
there is an improvement of 0.3 dv from SNCR, 0.6 dv from SCR on unit 1, 
and 0.7 dv from SCR at 0.05 lb/MMBtu on both units. These improvements 
are smaller than for the other facilities because the benefit from SCR 
at 0.08 lb/MMBtu on unit 2 is subsumed in the baseline. Any of these 
improvements would contribute to improved visibility, though SNCR on 
unit 2 only marginally so. SCR is the superior option for visibility, 
with the more stringent SCR at 0.05 lb/MMBtu on unit 2 giving a 
slightly greater benefit than when that limit is applied only to unit 
1. The cumulative improvements corresponding to the three control 
scenarios are 1.3 dv, 2.8 dv, and 3.1 dv. Only the SCR scenarios give 
improvements exceeding 0.5 dv. The modeled degree of visibility 
improvements supports either SCR scenario as BART for Coronado.

                Table 23--Coronado Units 1 and 2: EPA's Visibility Improvements From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                    Improvement     Improvement     Improvement
                  Class I area                       Baseline      from SNCR on    from SCR .05   from SCR, 0.05
                                                    impact (dv)     unit 1 (dv)   on unit 1 (dv)   lb/MMBtu (dv)
----------------------------------------------------------------------------------------------------------------
Bandelier NM....................................            0.37            0.07            0.19            0.20
Chiricahua NM...................................            0.20            0.03            0.07            0.08
Chiricahua WA...................................            0.21            0.04            0.08            0.09
Galiuro WA......................................            0.20            0.03            0.08            0.09
Gila WA.........................................            1.23            0.33            0.60            0.66

[[Page 42864]]

 
Grand Canyon NP.................................            0.24            0.03            0.10            0.11
Mazatzal WA.....................................            0.20            0.03            0.06            0.07
Mesa Verde NP...................................            0.40            0.10            0.19            0.20
Mount Baldy WA..................................            0.87            0.16            0.42            0.44
Petrified Forest NP.............................            1.22            0.22            0.47            0.56
Pine Mountain WA................................            0.14            0.02            0.04            0.05
Saguaro NP......................................            0.12            0.01            0.03            0.04
San Pedro Parks WA..............................            0.54            0.11            0.28            0.30
Sierra Ancha WA.................................            0.24            0.04            0.06            0.07
Superstition WA.................................            0.21            0.02            0.06            0.06
Sycamore Canyon WA..............................            0.16            0.02            0.06            0.06
Cumulative dv...................................            6.54            1.25            2.78            3.07
 areas >=0.5...........................               4            0               1               2
$/max dv, millions..............................  ..............          $11.9           $16.2           $15.0
$/cumulative dv, millions.......................  ..............           $3.1            $3.5            $3.2
----------------------------------------------------------------------------------------------------------------
Note: Costs of implementing SCR at 0.08 lb/MMBtu on unit 2 are not included.

c. EPA's BART Determinations
    As noted above, we have considered the remaining useful life of the 
source by incorporating a 20-year amortization period into our control 
cost calculations. The presence of existing pollution control 
technology is reflected in the cost and visibility factors as a result 
of selection of the baseline period for cost calculations and 
visibility modeling. For Coronado Unit 1, a baseline period (May 2009 
to December 2010) was selected that reflects the currently existing 
pollution control technology (LNB with OFA). For Coronado Unit 2, a 
baseline of 0.080 lb/MMBtu was selected to reflect the requirements of 
the consent decree decribed above. In addition, as noted above, we have 
received information from SRP indicating that the design and 
construction of SCR at Unit 2 have aleady progressed significantly. To 
the extent that we receive additional documentation establishing the 
status of this effort, we will take this information into consideration 
under the factors of ``costs of compliance'' and ``existing controls.''
    In examining energy and non-air quality impacts, we note certain 
potential impacts resulting from the use of ammonia injection 
associated with the SNCR and SCR control options, but do not consider 
these impacts sufficient enough to warrant eliminating any of the 
available control technologies.
    Our consideration of degree of visibility improvement focuses 
primarily on the improvement from base case impacts associated with 
each control option. While each of the available NOX control 
options achieves some degree of visibility improvement, we consider the 
improvement associated with the most stringent option, SCR with LNB and 
OFA, to be substantial. Our consideration of cost of compliance focuses 
primarily on the cost-effectiveness of each control option, as measured 
in cost per ton and incremental cost per ton of each control option. 
Despite the fact that the most stringent option, SCR with LNB and OFA, 
is the most expensive of the available control options, we consider it 
cost-effective on average basis as well as on an incremental basis when 
compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control 
option, SCR with LNB and OFA, to be cost-effective and to result in 
substantial visibility improvement, and that the energy and non-air 
quality impacts are not sufficient to warrant eliminating it from 
consideration. Therefore, we propose to determine that NOX 
BART for Coronado Units 1 and 2 is SCR with LNB and OFA. At Unit1 we 
propose an emission limit for NOX of 0.050 lb/MMBtu, based 
on a rolling 30-boiler-operating-day average.
    At Unit 2, we propose an emission limit of 0.080 lb/MMBtu, which is 
consistent with the emission limit in the consent decree. We 
acknowledge that the emission limit of 0.080 lb/MMBtu established in 
the consent decree was not the result of a BART five-factor analysis, 
nor does the consent decree indicate that SCR at 0.080 lb/MMBtu 
represents BART. Nonetheless, given the compliance schedule established 
in the consent decree and the preliminary information received from SRP 
regarding the status of design and construction of the SCR system, it 
appears that achieving a 0.050 lb/MMBtu emission rate may not be 
technically feasible. Even if it is feasible, achievement of this 
emission rate may not be cost-effective. Therefore, we are proposing an 
emission limit of 0.080 lb/MMBtu as BART for NOX at Unit 2. 
However, if we do not receive sufficient documentation establishing 
that achievement of a more stringent limit is infeasible or not cost-
effective, then we may determine that a more stringent limit for this 
unit is required in our final action.
    For Coronado Unit 2, we are proposing a compliance date of June 1, 
2014 for the NOX limit, consistent with the consent decree 
described above.
    Finally, at Coronado Unit 1, we are proposing to require compliance 
with the NOX limit within five years of final promulgation 
of this FIP consistent with the compliance times for the NOX 
limits at the other units. However, we are seeking comment on whether a 
shorter compliance schedule may be practicable for this unit.

C. Enforceability Requirements

    In order to meet the requirements of the RHR and the CAA and to 
ensure that the BART limits are practically enforeceable, we propose to 
include the following elements in the FIP:
    1. Requirements for use of continuous emission monitoring systems 
(CEMS) (and associated quality assurance procedures) to determine 
compliance with NOX and SO2 limits.
    2. Use of 30-day rolling averaging period and definition of boiler 
operating day, consistent with the BART Guidelines.
    3. Requirements for annual performance stack tests and 
implementation of Compliance Assurance Monitoring (CAM) plan to 
establish compliance with PM emission limits.

[[Page 42865]]

    4. Recordkeeping and reporting requirements.
    5. Requirement to maintain and operate the unit including 
associated air pollution control equipment in a manner consistent with 
good air pollution control practices for minimizing emissions.

The foregoing requirements would apply to all units.
    In addition, we are proposing specific compliance deadlines for 
each of ADEQ's BART emissions limits that we are proposing to approve. 
In most instances, the control technologies required to meet these 
limits have already been installed. See Table 3. Therefore, we are 
proposing to require compliance with the applicable emissions limits 
for PM and SO2 within 180 days of final promulgation of this 
FIP, except that at Cholla Unit 2, we propose to require compliance 
with the PM limit by January 1, 2015, consistent with ADEQ's BART 
determination.
    Regarding NOX, we propose to allow up to five years from 
final promulgation of this FIP for each unit subject to an emission 
limit consistent with SCR, with the exception of Coronado Unit 2. This 
proposal is based on the results of two analyses of SCR installation 
times, as summarized in EPA Region 6's Complete Response to Comments 
for NM Regional Haze/Visibility Transport FIP.\115\ An analysis 
performed by EPA Region 6, based on a review of a number of sources, 
found that the design and installation of SCR took between 18 and 69 
months. A separate analysis performed for the Utility Air Regulatory 
Group (UARG) found that it took 28 to 62 months to design and install 
the 14 SCRs in its sample.\116\ In the case of the BART FIP for San 
Juan Generating Station, EPA Region 6 initially proposed to allow a 
three-year compliance time frame for design and installation of SCR, 
but ultimately allowed for a five-year compliance schedule.\117\ We 
also note that SCR installations often trigger Prevention of 
Significant of Deterioration permitting requirements because they 
constitute physical changes to an existing emission unit that may 
result in increased emissions of sulfuric acid mist. Therefore, we are 
proposing a five-year compliance time frame, which would provide 
adequate time for SCR design and installation based on the high-end of 
the range of dates in the analyses cited above. However, we are seeking 
comment on whether these compliance dates are reasonable and consistent 
with the requirement of the CAA and the RHR that BART be installed ``as 
expeditiously as practicable.'' We are specifically seeking comment on 
whether the outage schedule for any of these units may warrant a 
shorter compliance schedule (up to five years). If we receive 
information during the comment period that establishes that a shorter 
compliance timeframe is appropriate for one or more of these units, we 
may finalize a different compliance date.
---------------------------------------------------------------------------

    \115\ Available on regulations.gov, docket no. EPA-R06-OAR-2010-
0846, pp. 70-72. See also 76 FR at 52408-09.
    \116\ J. Edward Cichanowicz, Implementation Schedule for 
Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization 
(FGD) Process Equipment (Oct. 10, 2010).
    \117\ 76 FR at 52408-09.
---------------------------------------------------------------------------

VIII. Summary of EPA's Proposed Action

    Based on the available control technologies and the five factors 
discussed in more detail below, EPA is proposing to require these 
facilities to meet NOX, PM10 and SO2 
emission limits as listed in Table 24. With the exception of Apache 
Unit 1, the NOX emission limits in Table 24 are proposed as 
part of EPA's FIP, based on the five factor analyses summarized in 
Section VII. The PM10 and SO2 emission limits in 
Table 24 are taken from ADEQ's BART determinations for these 
facilities, proposed for EPA approval in this action. EPA is seeking 
comment on alternative PM10 and SO2 emissions 
limits for Apache Generating Station Units 2 and 3; Cholla Power Plant 
Units 2, 3 and 4; and Coronado Units 1 and 2 as described in Section 
VI.B. We are also seeking comment on whether a test method other than 
EPA Method 201/202 should be allowed or required for establishing 
compliance with the PM10 limits that we are proposing to 
approve. Finally, we are proposing compliance dates and specific 
requirements for monitoring, recordkeeping, reporting and equipment 
operation and maintenance for all of the units covered by this action. 
Our proposed compliance dates are summarized in Table 25. We are 
seeking comment on whether these compliance dates are reasonable and 
consistent with the requirement of the CAA and the RHR that BART be 
installed ``as expeditiously as practicable.'' We are also taking 
comment on whether it would be technically feasible and cost-effective 
for Coronado Unit 2 to meet an emissions limit of 0.050 lb/MMBtu for 
NOX.
    EPA takes very seriously a decision to disapprove a state plan. In 
this instance, we believe that Arizona's SIP meets the CAA requirements 
with respect to its SO2 and PM10 limits, but the 
NOX BART determinations for the coal-fired units are neither 
consistent with the requirements of the Act nor with BART decisions 
that other states have made. As a result, EPA considers that this 
proposed disapproval is the only path that is consistent with the Act 
at this time.

                                    Table 24--Summary of BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                                             Emission limitation (lb/MMBtu) (rolling 30-boiler-
                                                                           operating-day average)
                           Unit                            -----------------------------------------------------
                                                                   NOX              PM10               SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1..........................             0.056            0.0075           0.00064
Apache Generating Station Unit 2..........................             0.050              0.03              0.15
Apache Generating Station Unit 3..........................             0.050              0.03              0.15
Cholla Power Plant Unit 2.................................             0.050             0.015              0.15
Cholla Power Plant Unit 3.................................             0.050             0.015              0.15
Cholla Power Plant Unit 4.................................             0.050             0.015              0.15
Coronado Generating Station Unit 1........................             0.050              0.03              0.08
Coronado Generating Station Unit 2........................             0.080              0.03              0.08
----------------------------------------------------------------------------------------------------------------


[[Page 42866]]


                                   Table 25--Summary of BART Compliance Dates
----------------------------------------------------------------------------------------------------------------
                                                                  Compliance date
               Unit               ------------------------------------------------------------------------------
                                              NOX                       PM10                       SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1.  Five years...............  180 days................  180 days.
Apache Generating Station Unit 2.  Five years...............  180 days................  180 days.
Apache Generating Station Unit 3.  Five years...............  180 days................  180 days.
Cholla Power Plant Unit 2........  Five years...............  January 1, 2015.........  180 days.
Cholla Power Plant Unit 3........  Five years...............  180 days................  180 days.
Cholla Power Plant Unit 4........  Five years...............  180 days................  180 days.
Coronado Generating Station Unit   Five years...............  180 days................  180 days.
 1.
Coronado Generating Station Unit   June 1, 2014.............  180 days................  180 days.
 2.
----------------------------------------------------------------------------------------------------------------


                          Table 26--Summary of Arizona's Proposed BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                                             Emission limitation (lb/MMBtu) (rolling 30-boiler-
                                                                           operating-day average)
                           Unit                            -----------------------------------------------------
                                                                   NOX              PM10               SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1..........................             0.056            0.0075           0.00064
Apache Generating Station Unit 2..........................               n/a              0.03              0.15
Apache Generating Station Unit 3..........................               n/a              0.03              0.15
Cholla Power Plant Unit 2.................................               n/a             0.015              0.15
Cholla Power Plant Unit 3.................................               n/a             0.015              0.15
Cholla Power Plant Unit 4.................................               n/a             0.015              0.15
Coronado Generating Station Unit 1........................               n/a              0.03              0.08
Coronado Generating Station Unit 2........................               n/a              0.03              0.08
----------------------------------------------------------------------------------------------------------------


                          Table 27--Summary of EPA's Proposed FIP BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                                             Emission limitation (lb/MMBtu) (rolling 30-boiler-
                                                                           operating-day average)
                           Unit                            -----------------------------------------------------
                                                                   NOX              PM10               SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1..........................               n/a               n/a               n/a
Apache Generating Station Unit 2..........................             0.050               n/a               n/a
Apache Generating Station Unit 3..........................             0.050               n/a               n/a
Cholla Power Plant Unit 2.................................             0.050               n/a               n/a
Cholla Power Plant Unit 3.................................             0.050               n/a               n/a
Cholla Power Plant Unit 4.................................             0.050               n/a               n/a
Coronado Generating Station Unit 1........................             0.050               n/a               n/a
Coronado Generating Station Unit 2........................             0.080               n/a               n/a
----------------------------------------------------------------------------------------------------------------

IX. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) 
and is therefore not subject to review under Executive Orders 12866 and 
13563 (76 FR 3821, January 21, 2011). As discussed in detail in section 
C below, the proposed FIP applies to only three facilities. It is 
therefore not a rule of general applicability.

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Under the Paperwork Reduction Act, a ``collection of 
information'' is defined as a requirement for ``answers to * * * 
identical reporting or recordkeeping requirements imposed on ten or 
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP 
applies to just three facilities, the Paperwork Reduction Act does not 
apply. See 5 CFR 1320(c). Burden means the total time, effort, or 
financial resources expended by persons to generate, maintain, retain, 
or disclose or provide information to or for a Federal agency. This 
includes the time needed to review instructions; develop, acquire, 
install, and utilize technology and systems for the purposes of 
collecting, validating, and verifying information, processing and 
maintaining information, and disclosing and providing information; 
adjust the existing ways to comply with any previously applicable 
instructions and requirements; train personnel to be able to respond to 
a collection of information; search data sources; complete and review 
the collection of information; and transmit or otherwise disclose the 
information. An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid Office of Management and Budget (OMB) control number. 
The OMB control numbers for our regulations in 40 CFR are listed in 40 
CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial

[[Page 42867]]

number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions. For purposes 
of assessing the impacts of today's proposed rule on small entities, 
small entity is defined as: (1) A small business as defined by the 
Small Business Administration's (SBA) regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for 
profit enterprise which is independently owned and operated and is not 
dominant in its field. Firms primarily engaged in the generation, 
transmission, and/or distribution of electric energy for sale are small 
if, including affiliates, the total electric output for the preceding 
fiscal year did not exceed 4 million megawatt hours. AEPCO sold under 3 
million megawatt hours in 2011. APS and SRP are not small entities. 
After considering the economic impacts of this proposed action on small 
entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
The FIP for the three Arizona facilities being proposed today does not 
impose new requirements on a substantial number of small entities. The 
proposed partial approval of the SIP, if finalized, merely approves 
state law as meeting Federal requirements and imposes no additional 
requirements beyond those imposed by state law. See Mid-Tex Electric 
Cooperative, Inc. v. FERC, 773 F.2d 327 (DC Cir. 1985). Although a 
regulatory flexibility analysis as specified by the RFA is not required 
when a rule has some impact on one small entity, EPA policy is to 
assess the direct adverse impact of every rule on small entities and 
minimize any adverse impact to the extent feasible, regardless of the 
magnitude of the impact or number of small entities affected.\118\ 
Using easily available public information,\119\ EPA estimates that the 
annualized cost of requiring SCR in Units 1 and 2 would likely be in 
the range of 3 percent of AEPCO's assets and between 6 and 7 percent of 
AEPCO's annual sales. EPA requested information from AEPCO on the 
economics of operating Apache Generating Station and what impact the 
installation of SCR may have on the economics of operating Apache 
Generating Station.
---------------------------------------------------------------------------

    \118\ See Docket Item A-22 Final Guidance for EPA Rulewriters: 
Regulatory Flexibility Act as Amended by the Small Business and 
Regulatory Enforcement Fairness Act, November 2006 at 3.
    \119\ See Docket Item H-1 Arizona Electric Power Cooperative, 
Inc. Annual Report Electric for Year Ending December 31, 2011 
submitted to Arizona Corporation Commission Utilities Division, 
available at http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf.
---------------------------------------------------------------------------

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more 
(adjusted for inflation) in any 1 year. Before promulgating an EPA rule 
for which a written statement is needed, section 205 of UMRA generally 
requires EPA to identify and consider a reasonable number of regulatory 
alternatives and adopt the least costly, most cost-effective, or least 
burdensome alternative that achieves the objectives of the rule. The 
provisions of section 205 of UMRA do not apply when they are 
inconsistent with applicable law. Moreover, section 205 of UMRA allows 
EPA to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before EPA establishes any regulatory requirements that 
may significantly or uniquely affect small governments, including 
Tribal governments, it must have developed under section 203 of UMRA a 
small government agency plan. The plan must provide for notifying 
potentially affected small governments, enabling officials of affected 
small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    Under Title II of UMRA, EPA has determined that this proposed rule 
does not contain a Federal mandate that may result in expenditures that 
exceed the inflation-adjusted UMRA threshold of $100 million by State, 
local, or Tribal governments or the private sector in any 1 year. In 
addition, this proposed rule does not contain a significant Federal 
intergovernmental mandate as described by section 203 of UMRA nor does 
it contain any regulatory requirements that might significantly or 
uniquely affect small governments.

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces 
Executive Orders 12612 (Federalism) and 12875 (Enhancing the 
Intergovernmental Partnership). Executive Order 13132 requires EPA to 
develop an accountable process to ensure ``meaningful and timely input 
by State and local officials in the development of regulatory policies 
that have federalism implications.'' ``Policies that have federalism 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.'' Under Executive Order 13132, EPA may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the Federal government provides the funds necessary to pay the direct 
compliance costs incurred by State and local governments, or EPA 
consults with State and local officials early in the process of 
developing the proposed regulation. EPA also may not issue a regulation 
that has federalism implications and that preempts State law unless the 
Agency consults with State and local officials early in the process of 
developing the proposed regulation.
    This rule will not have substantial direct effects on the States, 
on the relationship between the national government and the States, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132, because it 
addresses the State not fully meeting its obligation to prohibit 
emissions from interfering with other states measures to protect 
visibility established in the CAA. Thus, Executive Order 13132 does not 
apply to this action. In the spirit of Executive Order 13132, and 
consistent with EPA policy to promote communications between EPA and 
State and local governments, EPA specifically solicits comment on this 
proposed rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled Consultation and Coordination With 
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA

[[Page 42868]]

to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' This proposed rule does not have 
tribal implications, as specified in Executive Order 13175. It will not 
have substantial direct effects on tribal governments. Thus, Executive 
Order 13175 does not apply to this rule. EPA specifically solicits 
additional comment on this proposed rule from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks (62 FR 19885,April 23, 1997), applies to 
any rule that: (1) Is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. EPA interprets EO 13045 as 
applying only to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the EO 
has the potential to influence the regulation. This action is not 
subject to EO 13045 because it implements specific standards 
established by Congress in statutes. However, to the extent this 
proposed rule will limit emissions of NOX, SO2, 
and PM10, the rule will have a beneficial effect on 
children's health by reducing air pollution.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical. The EPA believes that VCS are inapplicable to this action. 
Today's action does not require the public to perform activities 
conducive to the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    We have determined that this proposed rule, if finalized, will not 
have disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse human health or 
environmental effects on any population, including any minority or low-
income population. This proposed federal rule limits emissions of 
NOX, from three facilities in Arizona. The partial approval 
of the SIP for SO2, and PM10, if finalized, 
merely approves state law as meeting Federal requirements and imposes 
no additional requirements beyond those imposed by state law.

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by 
reference, Intergovernmental relations, Nitrogen dioxide, Particulate 
matter, Reporting and recordkeeping requirements, Sulfur dioxide, 
Visibility, Volatile organic compounds.

    Dated: July 2, 2012.
Jared Blumenfeld,
Regional Administrator, Region 9.

    Part 52, chapter I, title 40 of the Code of Federal Regulations is 
proposed to be amended as follows:

PART 52--[AMENDED]

    1. The authority citation for Part 52 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart D--Arizona

    2. Add paragraph (e) to Sec.  52.145, to read as follows:


Sec.  52.145  Visibility Protection.

* * * * *
    (e) Federal implementation plan for regional haze.
    (1) Applicability. This paragraph (e) applies to each owner/
operator of the following coal-fired electricity generating units 
(EGUs) in the state of Arizona: Apache Generating Station, Units 2 and 
3; Cholla Power Plant, Units 2, 3, and 4; and Coronado Generating 
Station, Units 1 and 2. This paragraph (e) also applies to each owner/
operator of the following natural gas-fired EGU in the state of 
Arizona: Apache Generating Station Unit 1. The provisions of this 
paragraph (e) are severable, and if any provision of this paragraph 
(e), or the application of any provision of this paragraph (e) to any 
owner/operator or circumstance, is held invalid, the application of 
such provision to other owner/operators and other circumstances, and 
the remainder of this paragraph (e), shall not be affected thereby.
    (2) Definitions. Terms not defined below shall have the meaning 
given to them in the Clean Air Act or EPA's regulations implementing 
the Clean Air Act. For purposes of this paragraph (e):
    ADEQ means the Arizona Department of Environmental Quality.
    Boiler operating day means a 24-hour period between 12 midnight and 
the following midnight during which any fuel is combusted at any time 
in the steam-generating unit. It is not necessary for fuel to be 
combusted the entire 24-hour period.
    Coal-fired unit means any of the EGUs identified in paragraph 
(e)(1) of this section, except for Apache Generating Station, Unit 1.
    Continuous emission monitoring system or CEMS means the equipment 
required by 40 CFR part 75 and this paragraph (e).
    Emissions limitation or emissions limit means the Federal emissions 
limitation required by this paragraph (e) and the applicable 
PM10 and SO2 emissions limits for Apache 
Generating Station, Cholla Power Plant, and Coronada Generating Station 
submitted to EPA as part of the Arizona Regional Haze State 
Implementation Plan in a letter dated February 28, 2011 and approved 
into the Arizona state implementation plan on [INSERT DATE OF 
PUBLICATION OF FINAL ACTION IN THE Federal Register].
    lb means pound(s).
    NOX means nitrogen oxides expressed as nitrogen dioxide 
(NO2).
    Owner(s)/operator(s) means any person(s) who own(s) or who 
operate(s), control(s), or supervise(s) one more of

[[Page 42869]]

the units identified in paragraph (e)(1) of this section.
    MMBtu means million British thermal unit(s).
    Operating hour means any hour that fossil fuel is fired in the 
unit.
    Pipeline natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions, and which is provided by a supplier through a pipeline. 
Pipeline natural gas contains 0.5 grains or less of total sulfur per 
100 standard cubic feet. Additionally, pipeline natural gas must either 
be composed of at least 70 percent methane by volume or have a gross 
calorific value between 950 and 1100 Btu per standard cubic foot.
    PM10 means filterable total particulate matter less than 10 microns 
and the condensable material in the impingers as measured by Methods 
201A and 202.
    Regional Administrator means the Regional Administrator of EPA 
Region IX or his/her authorized representative.
    SO2 means sulfur dioxide.
    Unit means any of the EGUs identified in paragraph (e)(1) of this 
section.
    (3) Emission Limitations. The owner/operator of each unit subject 
to this paragraph (e) shall not emit or cause to be emitted 
NOX in excess of the following limitations, in pounds per 
million British thermal units (lb/MMBtu). Each emission limit shall be 
based on a rolling 30-boiler-operating-day average, unless otherwise 
indicated in specific paragraphs. Apache Generating Station Unit 1 
shall operate only on pipeline natural gas.

------------------------------------------------------------------------
                                                              Federal
                           Unit                               emission
                                                             limit  NOX
------------------------------------------------------------------------
Apache Generating Station Unit 1.........................          0.056
Apache Generating Station Unit 2.........................          0.050
Apache Generating Station Unit 3.........................          0.050
Cholla Power Plant Unit 2................................          0.050
Cholla Power Plant Unit 3................................          0.050
Cholla Power Plant Unit 4................................          0.050
Coronado Generating Station Unit 1.......................          0.050
Coronado Generating Station Unit 2.......................          0.08
------------------------------------------------------------------------

     (4) Compliance Dates.
    i. The owners/operators of each unit subject to paragraph (e) shall 
comply with the emissions limitations and other requirements of this 
paragraph (e) as expeditiously as practicable, but in no event later 
than the following dates:

----------------------------------------------------------------------------------------------------------------
                                                                    Compliance date
                 Unit                 --------------------------------------------------------------------------
                                                 NOX                      PM10                     SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station, Unit 1....  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION OF FINAL     PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                        ACTION IN THE Federal    ACTION IN THE Federal    ACTION IN THE Federal
                                        Register].               Register].               Register]
Apache Generating Station, Unit 2....  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION OF FINAL     PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                        ACTION IN THE Federal    ACTION IN THE Federal    ACTION IN THE Federal
                                        Register].               Register].               Register]
Apache Generating Station, Unit 3....  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION OF FINAL     PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                        ACTION IN THE Federal    ACTION IN THE Federal    ACTION IN THE Federal
                                        Register].               Register].               Register]
Cholla Power Plant, Unit 2...........  [INSERT DATE FIVE YEARS  January 1, 2015........  [INSERT DATE 180 DAYS
                                        AFTER DATE OF                                     AFTER DATE OF
                                        PUBLICATION OF FINAL                              PUBLICATION OF FINAL
                                        ACTION IN THE Federal                             ACTION IN THE Federal
                                        Register].                                        Register]
Cholla Power Plant, Unit 3...........  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION IN THE       PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                        Federal Register].       ACTION IN THE Federal    ACTION IN THE Federal
                                                                 Register].               Register]
Cholla Power Plant, Unit 4...........  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION IN THE       PUBLICATION IN THE       PUBLICATION IN THE
                                        Federal Register].       Federal Register].       Federal Register]
Coronado Generating Station, Unit 1..  [INSERT DATE FIVE YEARS  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                        AFTER DATE OF            AFTER DATE OF            AFTER DATE OF
                                        PUBLICATION OF FINAL     PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                        ACTION IN THE Federal    ACTION IN THE Federal    ACTION IN THE Federal
                                        Register].               Register].               Register]
Coronado Generating Station, Unit 2..  June 1, 2014...........  [INSERT DATE 180 DAYS    [INSERT DATE 180 DAYS
                                                                 AFTER DATE OF            AFTER DATE OF
                                                                 PUBLICATION OF FINAL     PUBLICATION OF FINAL
                                                                 ACTION IN THE Federal    ACTION IN THE Federal
                                                                 Register].               Register]
----------------------------------------------------------------------------------------------------------------


[[Page 42870]]

     (5) Compliance determinations for NOX and SO2.
    i. Continuous emission monitoring system.
    A. At all times after the compliance date specified in paragraph 
(e)(4) of this section, the owner/operator of each coal-fired unit 
shall maintain, calibrate, and operate a CEMS, in full compliance with 
the requirements found at 40 CFR part 75, to accurately measure 
SO2, NOX, diluent, and stack gas volumetric flow 
rate from each unit. Apache Unit 1 NOX and diluent CEMs 
shall be operated to meet the requirements of Part 75. Valid data means 
data recorded when the CEMS is not out-of-control as defined by Part 
75. All valid CEMS hourly data shall be used to determine compliance 
with the emission limitations for NOX and SO2 in 
paragraph (e)(3) of this section for each unit. When the CEMS is out-
of-control as defined by Part 75, that CEMs data shall be treated as 
missing data and not used to calculate the emission average.
    B. The owner/operator of each unit shall comply with the quality 
assurance procedures for CEMS found in 40 CFR part 75. In addition to 
these Part 75 requirements, relative accuracy test audits shall be 
performed for both the NOX pounds per hour measurement and 
the heat input measurement. These shall have relative accuracies of 
less than 20%. This testing shall be evaluated each time the CEMS 
undergo relative accuracy testing. Heat input for Apache Unit 1 shall 
be measured in accordance with Part 75 fuel gas measurement procedures 
found in Part 75 Appendix D.
    ii. Compliance determinations for NOX.
    A. The 30-day rolling average NOX emission rate for each 
unit shall be calculated in accordance with the following procedure: 
First, sum the total pounds of NOX emitted from the unit 
during the current boiler operating day and the previous twenty-nine 
(29) boiler-operating days; second, sum the total heat input to the 
unit in MMBtu during the current boiler operating day and the previous 
twenty-nine (29) boiler-operating days; and third, divide the total 
number of pounds of NOX emitted during the thirty (30) 
boiler-operating days by the total heat input during the thirty (30) 
boiler-operating days. A new 30-day rolling average NOX 
emission rate shall be calculated for each new boiler operating day. 
Each 30-day rolling average NOX emission rate shall include 
all emissions that occur during all periods within any boiler operating 
day, including emissions from startup, shutdown, and malfunction.
    B. If a valid NOX pounds per hour or heat input is not 
available for any hour for a unit, that heat input and NOX 
pounds per hour shall not be used in the calculation of the 30-day 
rolling average. Each unit must obtain valid hourly data for at least 
90% of the operating hours for each calendar quarter.
    iii. Compliance determinations for SO2.
    A. The 30-day rolling average SO2 emission rate for each 
coal-fired unit shall be calculated in accordance with the following 
procedure: First, sum the total pounds of SO2 emitted from 
the unit during the current boiler operating day and the previous 
twenty-nine (29) boiler-operating days; second, sum the total heat 
input to the unit in MMBtu during the current boiler-operating day and 
the previous twenty-nine (29) boiler-operating day; and third, divide 
the total number of pounds of SO2 emitted during the thirty 
(30) boiler-operating days by the total heat input during the thirty 
(30) boiler-operating days. A new 30-day rolling average SO2 
emission rate shall be calculated for each new boiler operating day. 
Each 30-day rolling average SO2 emission rate shall include 
all emissions that occur during all periods within any boiler-operating 
day, including emissions from startup, shutdown, and malfunction.
    B. If a valid SO2 pounds per hour or heat input is not 
available for any hour for a unit, that heat input and SO2 
pounds per hour shall not be used in the calculation of the 30-day 
rolling average. Each unit must obtain valid hourly data for at least 
90% of the operating hours for each calendar quarter.
    (6) Compliance Determinations for Particulate Matter. Compliance 
with the particulate matter emission limitation for each coal-fired 
unit shall be determined from annual performance stack tests. Within 
sixty (60) days of the compliance deadline specified in paragraph 
(e)(4) of this section, and on at least an annual basis thereafter, the 
owner/operator of each unit shall conduct a stack test on each unit to 
measure PM-10 using 40 CFR part 51, appendix M, Method 201A/202. A test 
protocol shall be submitted to EPA a minimum of 30 days prior to the 
scheduled testing. Each test shall consist of three runs, with each run 
at least 120 minutes in duration and each run collecting a minimum 
sample of 60 dry standard cubic feet. Results shall be reported in lb/
MMBtu using the calculation in 40 CFR part 60 appendix A Method 19. In 
addition to annual stack tests, owner/operator shall monitor 
particulate emissions for compliance with the emission limitations in 
accordance with the applicable Compliance Assurance Monitoring (CAM) 
plan developed and approved in accordance with 40 CFR part 64. The 
averaging time for any other demonstration of the PM-10 compliance or 
exceedance shall be based on a 6-hour average.
    (7) Recordkeeping. The owner or operator of each unit shall 
maintain the following records for at least five years:
    a. All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    b. Daily 30-day rolling emission rates for NOX and 
SO2 for each unit, calculated in accordance with paragraph 
(e)(5) of this section.
    c. Records of quality assurance and quality control activities for 
emissions measuring systems including, but not limited to, any records 
required by 40 CFR part 75.
    d. Records of the relative accuracy test for NOX and 
SO2 lb/hr measurement and hourly heat input.
    e. Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    f. Any other records required by 40 CFR part 75.
    (8) Reporting. All reports and notifications under this paragraph 
(e) shall be submitted to the Director of Enforcement Division, U.S. 
EPA Region IX, at 75 Hawthorne Street, San Francisco, CA 94105.
    a. The owner/operator shall notify EPA within two weeks after 
completion of installation of combustion controls or Selective 
Catalytic Reactors on any of the units subject to this section.
    b. Within 30 days after the applicable compliance date(s) in 
paragraph (e)(4) of this section and within 30 days of the end of each 
calendar quarter thereafter, the owner/operator of each unit shall 
submit a report that lists the daily 30-day rolling emission rates for 
NOX and SO2 for each unit, calculated in 
accordance with paragraph (e)(5) of this section. Included in this 
report shall be the results of any relative accuracy test audit 
performed during the calendar quarter.
    (9) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation

[[Page 42871]]

of any standard or applicable emission limit in the plan.
    (10) Equipment Operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (11) Affirmative Defense for Malfunctions. The following 
regulations are incorporated by reference and made part of this federal 
implementation plan: Rules R18-2-310 and R18-2-310.01, approved into 
the Arizona SIP at 40 CFR 52.120(c)(97)(i)(A).

[FR Doc. 2012-17659 Filed 7-19-12; 8:45 am]
BILLING CODE 6560-50-P